A review of global gas flaring and venting and impact on the environment: Case study of Iran

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ARTICLE IN PRESS

IJGGC-1800; No. of Pages 22

International Journal of Greenhouse Gas Control xxx (2016) xxx–xxx

Contents lists available at ScienceDirect

International Journal of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc

Review

A review of global gas flaring and venting and impact on the environment: Case study of Iran Mohammad Soltanieh a,∗ , Angineh Zohrabian b , Mohammad Javad Gholipour c , Eugenia Kalnay d a

Department of Chemical and Petroleum Engineering, Sharif University of Technology, Tehran, Iran Department of Energy Engineering, Sharif University of Technology, Tehran, Iran c Corporate Planning Department, National Iranian Oil Company (NIOC), Tehran, Iran d Department of Atmospheric and Oceanic Science, University of Maryland, College Park, MD, USA b

a r t i c l e

i n f o

Article history: Received 14 September 2015 Received in revised form 4 February 2016 Accepted 8 February 2016 Available online xxx Keywords: Gas flaring CO2 emission Emission factor Associated gas Environmental impact Reduction technologies

a b s t r a c t After a brief review of the global gas flaring and venting in oil industries including the emission of air pollutants and greenhouse gases and the amount of energy resources wasted, the focus is on Iran as a major oil producing and the world’s third largest gas flaring country. Gas flaring is also practiced in natural gas industries, petroleum refining and petrochemical plants, although the level of emission is very low compared with emissions from oil production. The historical emission of these gases globally and Iran specifically, geographic location of emission sources, composition of gases, environmental impacts of gas flaring and the current and future projects to mitigate emissions are evaluated and discussed. Emission factor, an indication of efficiency in oil production, varies widely among oil production sites around the world, from near zero to more than 50 standard cubic meters of flare gas per barrel of oil produced with an average value of about 5. Iran’s emission factor has fluctuated from around 1 to more than 16 according to the data of 1980–2012 with higher emission factors for offshore oil production. Data also show an increasing trend during 2010–2012 which could be due to the several technical reasons in oil productions as well as economic sanctions imposed on Iran. In addition, there is a great amount of uncertainty and discrepancies among various data sources in the emission factors due to the lack of actual measurements of the volume and composition of flare gas and the uncertainties in the data sources. This requires regulatory measures, investment by oil companies and international collaboration. The economic and technological constraints in implementing or delaying the gas flare reduction projects are evaluated and addressed, with successful case studies and best practices reviewed. In particular, the techno-economic constraints in implementing gas flaring reduction projects caused by international sanctions on Iran are analyzed. It is shown that despite the great loss of energy resources due to gas flaring, its adverse impacts on the local and global environment and the availability of the technologies to reduce emissions, flaring is still practiced in many parts of the world, which can be avoided if the necessary regulatory policies and measures are established at national levels and international collaboration can facilitate the investment by providing the required finance and technologies. At present the international activities to implement gas flaring project activities under the Clean Development Mechanism (CDM) of the Kyoto Protocol of the United Nations Framework Convention on Climate Change (UNFCCC) are very limited, but could be very effective in reducing emissions, if implemented. Due to the global demand and continued use of oil and gas in the next decades, there is an urgent need for reducing gas flaring emissions. This is not only the responsibility of the oil and gas companies, but also the responsibility of the national governments and the global community. © 2016 Elsevier Ltd. All rights reserved.

∗ Corresponding author at: Sharif University of Technology, Azadi Avenue, Tehran 11155/9464, Iran. E-mail addresses: [email protected] (M. Soltanieh), [email protected] (A. Zohrabian), [email protected] (M.J. Gholipour), [email protected] (E. Kalnay). http://dx.doi.org/10.1016/j.ijggc.2016.02.010 1750-5836/© 2016 Elsevier Ltd. All rights reserved.

Please cite this article in press as: Soltanieh, M., et al., A review of global gas flaring and venting and impact on the environment: Case study of Iran. Int. J. Greenhouse Gas Control (2016), http://dx.doi.org/10.1016/j.ijggc.2016.02.010

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2

Contents 1. 2.

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 Emission factor and combustion efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 2.1. Emission factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 2.2. Combustion efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 3. Global gas flaring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 4. Oil production and gas flaring – emission factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 5. Environmental impacts of gas flaring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 5.1. Acidity impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 5.2. Thermal impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 5.3. Heat radiation impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 5.4. Photochemical effect . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 5.5. Health impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 5.6. Agriculture impact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 6. Techno-economic constraints on reduction of flare emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 7. Gas flaring reduction technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 7.1. Re-injection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .00 7.2. Power generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 7.3. Pipeline natural gas (PNG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 7.4. Liquefied petroleum gas (LPG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 7.5. Liquefied natural gas (LNG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 7.6. Compressed natural gas (CNG) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 7.7. Natural gas hydrates (NGH) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 7.8. Gas-to-liquid (GTL) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 7.9. Methanol and ammonia production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 7.10. Comparison of technology options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 8. Best practice cases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 9. CDM projects for gas flaring reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 10. Gas flaring in Iran . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 10.1. Historical background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 10.2. Gas flaring sources in Iran . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 10.3. Natural gas supply and demand in Iran . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 10.4. Major gas gathering projects in Iran . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 10.4.1. AMAK projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 10.4.2. Kharg and Behregansar projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 10.4.3. SIRI project . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 10.5. Gas flaring laws and policies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 11. Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 Acknowledgment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 Appendix A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 Flare gas sampling, combustion efficiency, emission factor and composition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 00

1. Introduction Since the inception of oil exploration, drilling and production in the world more than one and a half century ago, gas flaring and venting has been practiced as a method to dispose of the gases associated with petroleum, mostly for safety, operational and economic reasons. The environmental awareness and concerns as well as the issue of sustainability on gas flaring have been raised only in the past few decades. Under the high-pressure condition in underground reservoirs, light hydrocarbons and other impurities are dissolved or dispersed in the heavier hydrocarbon compounds (crude oil). When this high pressure is reduced to the atmospheric condition at the well head in the surface facilities, the dissolved gases and other impurities are separated from liquids and released that are called the associated gases, flared or vented to the atmosphere. It should be noted that in addition to gas flaring and venting in oil production facilities (associated gas), in all oil and natural gas refineries as well as in petrochemical plants, there is always some amount of gases collected from various processes and sent to flare in tall stacks mostly for safety reasons or process operational considerations such as startups or shutdowns or process disruptions. This is called the non-associated gas that contains flammable and hazardous materials from pressure relief valves, process equipment

and shutdown operations. As it will be shown in Section 10.2, the contribution of this type of flaring is relatively very small compared with the associated gas flaring in oil production, however, the associated gas flaring and venting, is the focal area of this article. There are several reasons for gas flaring and venting in oil production including: • Lack of infrastructure to collect, treat, transport and utilize the associated gases; • The production site is remote from the market demand (such as offshore sites); • The small volume of the gas and its fluctuation, which make the design of facilities more uncertain and therefore uneconomical investment; • Impurities in the gas that require hard and expensive treatment methods (such as highly acidic gases); • Safety and operational reasons; Flaring wastes a valuable energy resource with great adverse environmental impacts and economic losses. According to GE Energy report (Farina, 2010) gas flaring is: (1) a multi-billion dollar waste; (2) a local environmental tragedy; (3) a global environmental issue; and (4) an energy problem that can be solved. As will

Please cite this article in press as: Soltanieh, M., et al., A review of global gas flaring and venting and impact on the environment: Case study of Iran. Int. J. Greenhouse Gas Control (2016), http://dx.doi.org/10.1016/j.ijggc.2016.02.010

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be discussed later in this paper, in 2011 the global gas flaring was around 140 billion cubic meters (Bcm) equivalent to 5% of global natural gas production, 10 billion USD lost revenue at $2.00 per MMBtu, 2.4 million barrels of oil equivalent per day. Environmentally, the 400 million tons per year of CO2 is roughly equivalent to (Farina, 2010): • • • • • •

the annual emissions from 77 million cars (34% of US fleet), 2% of global CO2 emissions from energy sources, 6 billion USD carbon credit value at $15.00 per metric ton, 20% of global steel industry CO2 emissions, 35% of global cement industry CO2 emissions, Output from 125 medium-sized coal power plants of about 63 gigawatts (GW) total (Farina, 2010).

According to a recent report by Olivier et al. (2013) of PBL, the Netherlands Environmental Assessment Agency, the global CO2 emissions of about 250 million tons from flaring of unused gas during oil production – comparable in magnitude with total CO2 emissions in a medium-sized country such as Spain – did not significantly change in 2011, after a steady decrease by about a quarter since 2003. This amount of CO2 emission is roughly equal to the estimated value by Carbon Dioxide Information Analysis Center (CDIAC) (CDIAC, 2014). In the same source (CDIAC), 360 million tons is reported for earlier years (1980s) (CDIAC, 2014). In another study an amount of around 150 billion cubic meters per year of global natural gas flaring has been reported, contaminating the environment with 400 million tons of CO2 annually (Andersen et al., 2012). Many factors are responsible for the gas-flaring-related CO2 emissions, discussed in a recently published article for the case of Nigeria (Hassan and Kouhy, 2013). These factors are produced crude oil, investment on gas utilization, gas-to-oil ratio, natural gas price, and flare reduction regulations and policies (Hassan and Kouhy, 2013). A recent investigation is done by Pourhassan and Taravat (2014), discussing on long term relationships between gas flaring volume, oil price, CO2 emission amount and the total natural resources rent of the GDP for eight developing countries including Iran. The light hydrocarbon gases (natural gas, which is mostly methane) are normally accompanied by non-methane volatile organic compounds (VOCs) and several other impurities such as sulfur gases, some inorganic salts (mainly as chlorates and sulfates of K, Mg, Na and Ca), carbon dioxide, nitrogen, polyaromatic hydrocarbons (PAHs), water, etc. The amount and composition of these gases vary significantly with time and from well to well depending upon the region of oil production and the pressure and temperature of the oil in the underground reservoir (Johnson et al., 2001). Detailed measurement of gas composition and volume of gas flaring and venting in most parts of the world is not available. However, a method for estimating the composition of gas being flared and vented at individual facilities has been proposed by Johnson and Coderre (2012). In relative term, the mass fraction of these gases compared with the crude oil production is usually small (in the range of 1–5 cubic meters of natural gas under atmospheric condition per barrels of oil produced – see Table 1 below for the global averages). This is equivalent to approximately 0.7–3.5 kg natural gas per barrel of oil produced (each barrel of oil is approximately 160 L and assuming a specific gravity of about 0.9, a barrel of oil is roughly 144 kg). Thus the mass fraction is roughly 0.0049–0.02431 or 0.49–2.43 wt% of associated gas per barrel of oil. This is the minimum to average value of emissions. As will be discussed in the following sections, there are certain countries where the amount of gas flared is much higher than these average values. However, in absolute term even this small fraction is significant globally as mentioned above and will be presented in detail in the following sections, causing

3

significant amount of energy resources loss and environmental pollution. If the associated gases are flared, most of this gas containing high fractions of methane is converted to CO2 , and if vented, methane with its high global warming potential (25 times more than CO2 – 100 years) and other air pollutants will be released to the atmosphere directly. Depending on the composition of the associated gases and the efficiency of combustion (to be discussed later), variable amounts of greenhouse gases CO2 and CH4 and air pollutants such as sulfur compounds (hydrogen sulfide, sulfur oxides, etc.), nitrogen oxides, carbon monoxide, soot and black carbon particles, volatile organic compounds (VOCs), polyaromatic hydrocarbons (PAHs) and toxic heavy metals such as mercury and nickel and other inorganic salts (mainly as chlorate and sulfate of K, Mg, Na and Ca) are emitted to the atmosphere (Leahey et al., 2001), causing severe local and regional air pollution and greenhouse effect. In 1996, the Alberta Research Council (ARC) released a report describing a multi-year experimentally-based study that culminated in field tests of one sweet and one sour gas flares. These measurements showed the existence of more than 150 volatile organic compounds (VOCs) including formaldehyde (H2 CO) and more than 60 poly aromatic hydrocarbons (PAH) in the plume of combustion products (Leahey et al., 2001; Kostiuk et al., 2004). It is well known that the presence of NOx and VOCs exacerbates the photochemical smog including ozone. In addition, there are significant amount of local thermal and noise pollution near the flaring sites. Low efficiency or poor combustion in the flare results in emission of methane, VOCs and other harmful air pollutants such as hydrogen sulfide and soot directly to the atmosphere. These pollutants under unfavorable atmospheric conditions (e.g. a temperature inversion) could have very serious health impacts like asthma, blood disorder, cancer, or chronic bronchitis on human living in the surrounding areas (Hassan and Kouhy, 2013; Younessi Sinaki et al., 2011). The gas flaring has continued to be practiced in the petroleum industries for techno-economic reasons despite the tremendous amount of energy loss and huge adverse environmental impacts. Although there are several initiatives at global and national levels, both state funded and by private sectors to end gas flaring, recent data show that emissions from gas flaring still continue at steady rate in an unsustainable manner. The objectives of this study are:

• To review the most recent available data and published papers or technical reports on global gas flaring; • To assess the emission factor1 based on the statistical data of global gas flaring and combustion efficiency; • To review the environmental impacts of gas flaring; • To assess the technologies for emission reduction from gas flaring; • To review the status of the gas flaring in Iran as a major oil and gas producing country and assess the existing and planned projects to reduce the gas flaring; • To identify the gaps and constraints in implementation of gas flaring projects in the oil and gas industries of Iran.

1 According to the terminology for calculating the air pollutants and greenhouse gases, emission factor is defined as the amount of the gas emitted to the atmosphere per unit of a particular activity, which in the case of gas flaring would be “cubic meters of flared gas/barrel of oil produced”. Some sources such as (Elvidge et al., 2009) call this ratio as flare efficiency, which may be misleading since this term is also used for combustion efficiency of the flare (ratio of flared gases compared to the vented gas). In this work emission factor is used to describe the amount of gas emitted per barrel of oil produced.

Please cite this article in press as: Soltanieh, M., et al., A review of global gas flaring and venting and impact on the environment: Case study of Iran. Int. J. Greenhouse Gas Control (2016), http://dx.doi.org/10.1016/j.ijggc.2016.02.010

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Table 1 Gas flaring, oil production and average 5-year emission factor for the period of 2007–2011 for top 20 gas flaring countries. 2007

2008

2009

2010

2011

5-year

Country

Gas flaring (Bcm/y)

Oil pro. (Mbbl/d)

Gas flaring (Bcm/y)

Oil pro. (Mbbl/d)

Gas flaring (Bcm/y)

Oil pro. (Mbbl/d)

Gas flaring (Bcm/y)

Oil pro. (Mbbl/d)

Gas flaring (Bcm/y)

Oil pro. (Mbbl/d)

EF (cm/bbl)

Russia Nigeria Iran Iraq USA1 Algeria Kazakhstan2 Angola Saudi Arabia3 Venezuela China Canada Libya Indonesia Mexico4 Qatar Uzbekistan Malaysia Oman Egypt Total top 20 Other countries Global

52.3 16.3 10.7 6.7 2.2 5.6 5.5 3.5 3.9 2.2 2.6 2 3.8 2.6 2.7 2.4 2.1 1.8 2 1.5 132.4 22 154.4

9878 2353 4039 2097 8469 1967 1446 1747 10,249 2682 3956 3449 1845 1041 3500 1121 112 705 715 674 62,045 22,281 84,326

42 15.5 10.8 7.1 2.4 6.2 5.4 3.5 3.9 2.7 2.5 1.9 4 2.5 3.6 2.3 2.7 1.9 2 1.6 124.5 22 146.5

9797 2169 4177 2385 8564 1955 1431 1979 10,782 2656 4037 3344 1874 1065 3184 1204 110 731 760 706 62,909 22,530 85,439

46.6 14.9 10.9 8.1 3.3 4.9 5 3.4 3.6 2.8 2.4 1.8 3.5 2.9 3 2.2 1.7 1.9 1.9 1.8 126.6 20 146.6

9934 2212 4178 2399 9134 1910 1542 1908 9819 2510 4067 3319 1790 1053 3001 1213 107 694 819 729 62,337 22,255 84,593

35.6 15 11.3 9 4.6 5.3 3.8 4.1 3.6 2.8 2.5 2.5 3.8 2.2 2.8 1.8 1.9 1.5 1.6 1.6 117.3 20 137.3

10,157 2459 4243 2403 9685 1881 1609 1948 10,642 2405 4363 3442 1789 1039 2979 1441 107 683 870 717 64,861 22,297 87,158

37.4 14.6 11.4 9.4 7.1 5 4.7 4.1 3.7 3.5 2.6 2.4 2.2 2.2 2.1 1.7 1.7 1.6 1.6 1.6 120.6 19 139.6

10,239 2555 4265 2629 10,136 1863 1638 1800 11,264 2489 4363 3597 502 1016 2960 1641 106 626 891 726 65,306 22,267 87,573

11.7 17.8 7.2 9.3 1.2 7.7 8.7 5.4 1.0 3.0 1.7 1.7 6.1 6.5 2.5 4.3 51.0 6.9 6.1 6.2 5.4 2.5 4.6

Source: Gas flaring data from NOAA Satellite and oil production data from EIA. Bold texts and numbers signify the importance and focal areas relevant to this paper. 1 Includes N. Dakota. 2 Reported much lower. 3 Includes share of neutral zones. 4 Reported much higher.

2. Emission factor and combustion efficiency 2.1. Emission factor The ratio of the amount of associated gas (usually in cubic meters) to the barrel of oil produced is called the emission factor (EF). As will be discussed in the following sections, emission factor varies significantly, from around 1 to more than 50 cubic meters per barrel of oil for different oil fields (see Table 1). However, the global five year average emission factor is around 5 cubic meters of gas per barrel of oil produced. For example, in 2010 for the world oil production of 87.2 million barrels per day (EIA, 2015) and the annual gas flaring estimate of 137.3 billion cubic meters (GGFR, 2012), the average emission factor was approximately 4.3 cubic meters of associated gas per barrel of oil produced.

2.2. Combustion efficiency The goal of a flare is to consume gases safely, reliably, and efficiently and, through oxidation, produce less harmful emissions to the atmosphere than simply venting the gases. The flare efficiency or combustion efficiency (CE) is a measure of the effectiveness of the combustion process in fully oxidizing the fuel to CO2 . CE affects the composition of emissions significantly. When inefficiencies occur, unburned fuel, carbon monoxide, and other products of incomplete combustion (e.g., soot, volatile organic compounds, hydrogen sulfide, etc.) are emitted into the atmosphere. If the flare stream contains methane, the unburned fuel represents an increase in greenhouse gas emissions. In the case of sour gas flares, any unburned fuel emissions are potentially toxic such as hydrogen sulfide that can raise health concerns for animals and people (Kostiuk et al., 2004; McDaniel, 1983).

The actual flare efficiency can only be obtained by measurement of composition of vented and flare gases. This is an expensive task, which is not undertaken by oil companies in all gas flaring sources. The mechanism of combustion reactions in an actual flare flame in the atmosphere is extremely complicated and the models for even simple fuels such as pure methane or hydrogen are not well understood (Hedayatzadeh, 2014). The composition of associated gases is measured mostly in those sources that have a planned project for implementation. For example, an offshore associated gas composition in Soroosh & Nowrooz oil sites of Iran in the Persian Gulf – which was implemented as CDM (Clean Development Mechanism) project under the Kyoto Protocol – is given in Appendix A. In this project flare combustion efficiency of 100% was assumed. Not all gas flaring data reported globally are based on measurements; rather they are estimated by satellite data or by expert judgment. It should be noted that flare efficiencies are not measured in Iran’s oil, gas and petrochemical industries and they are only checked by visual observation of experts (less smoke: higher efficiency). In another study, the measured average composition of flare fuel and assumed flaring combustion efficiencies of 98% and 90% were used to estimate CO2 emission factor of gas flaring in Iran’s oil and gas processing plants (Kahforoushan et al., 2011). Measurement of flare efficiency is difficult that requires special devices and analytical tools and thus default values are usually used to estimate emissions. Although use of emission factors makes the approximate emission estimation possible, it might have large uncertainty, as recently reported for carbon emissions from fossil fuel combustions in China (Liu et al., 2015). Recently a pilot scale flare has been used to find parametric emission factors for CO, CO2 , and NOx gases (Talebi et al., 2014). The emission estimation references along with the range of observed averaged emission factors for a set of experiments is reported in Appendix A. Details of combustion efficiency, flare sampling and concentration measurement as well as a semi-empirical model for

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Fig. 1. Gas flaring global distribution (a) top flaring countries adopted from (Farina, 2010), (b) countries’ flaring level adopted from NOAA (NOAA, 2014).

estimation of combustion efficiency in real crosswind conditions are also given in Appendix A.

3. Global gas flaring It is not in the scope of this paper to present an extensive detailed review of the global gas flaring sources and data. Rather, after a brief review of such data and the respective flare emissions, the focus will be on the status of the gas flaring projects in Iran, the third largest gas flaring country in the world, after Russia and Nigeria (GGFR, 2012). Gas flaring data are available through various sources including: national and international oil companies; International Energy Agency (IEA); US Energy Information Administration (EIA); the World Bank; Organization of Oil Exporting Countries (OPEC). The same sources also report greenhouse gas emissions. Greenhouse gas emissions from various sources including gas flaring are also available through the web site of United Nations Framework Convention on Climate Change (UNFCCC), where Annex I and NonAnnex I Parties to the Convention officially report their emissions. Fig. 1 shows the global map of gas flaring countries and Fig. 2 shows the global and regional gas flaring and crude oil production from 2000 to 2009, respectively (Farina, 2010). It should be mentioned that the flaring index as defined in Figure represents the inverse of the emission factor that was defined above, normalized to the base year of 2000. Thus lower flare index means higher emissions. From Fig. 2a it can be seen that whereas the global oil production and gas flaring during 2000–2009 have remained relatively constant, the emission factor has had an increasing trend till 2008 followed by a drop in 2009. The sharpest increase in gas flaring (emission factor) was observed in the Caspian region with the highest increase in the rate of oil production (Fig. 2b). Southeast Asia (Fig. 2c), Middle East (Fig. 2d), North America (Fig. 2f) and North Asia (Fig. 2g) have had relatively stable oil production and gas flaring in the mentioned period. Latin America (Fig. 2e), despite its relatively constant oil production and gas flaring, has had high emission factors between 2001 and 2007. Europe (Fig. 2h), has reduced its emission factor, partly due to its reduced oil production since 2004 and partly due to higher efficiency in oil production with reduced flaring. Countries with the largest satellite observed flaring emissions are the Russian Federation and Nigeria, with shares of global flaring emissions of about one quarter and one tenth, respectively, together accounted for 42% of those 400 million tons of CO2 . These two countries contributed also most to the global emission decrease over the last decade, followed by Iran, Iraq and the United States (Olivier et al., 2013). Nigerian gas flaring programs to end flaring in that country have recently been reviewed by Ite and Ibok (2013) and Ibitoye (2014).

Fig. 3 compares the global gas flaring data estimates from various sources. Two primary data sets are available. The first set is the data reported by international agencies such as the International Energy Agency (IEA) and agencies like EIA and Cedigas, essentially a compilation of nationally reported data by official bodies (that broadly captures the reported levels of gas flaring). No single agency has global data coverage so a hybrid compilation of data is developed from these sources and is referenced as the reporting agencies data set (Farina, 2010). The second set is prepared by the World Bank’s Global Gas Flaring Reduction Initiative (GGFR) led by the US National Oceanic Atmospheric Administration (NOAA) based on satellite tracking. Most gas flaring data available is estimates based on Defense Meteorological Satellite Program Operational Linescan System (DMSP-OLS) and Moderate Resolution Imaging Spectroradiometer (MODIS) satellite measurements. The night-time lights from gas flares observed by the satellites provide an estimate of the amounts of gas flared, when related to the reported flaring volumes available from the GGFR Partnership (Olivier et al., 2013; Elvidge et al., 2009). However, in the absence of measured data, the satellite data has excellent global coverage but also has several sources of uncertainty, including variation in flare intensity, inclusion of processing plant flaring, misidentification of flares, inability to track gas venting, and the difficulty in distinguishing flares from other urban lighting sources (Farina, 2010). The analysis of the error associated with satellite gas flaring estimates showed that 95% of the residuals of the calibration data were smaller than 2.98 Bcm (Elvidge et al., 2009). It should be mentioned that in 2012 NOAA has changed to a new sensor, for which cloud corrections and calibration to the flared gas volume can be carried out. According to Farina (2010) these two data sets cover approximately 98 percent of estimated global gas flaring. However, unless validated by measurements at different sites and countries, it seems that the uncertainty remains unverified. A recent study has been dedicated to estimate methane consumption of gas flaring using Visible Infrared Imaging Radiometer Suite (VIIRS) night-time data and to compare with NOAA satellite data. The comparison confirmed that the methane consumption estimation from VIIRS night-time data fitted reasonably well with limited field data including six stations located in North Dakota, whereas the NOAA night-fire estimates showed underestimation with Version 1 and overestimation with Version 2 (Zhang et al., 2015). Iran’s gas flaring data estimates from three sources of World Bank, EIA and the Hydrocarbon Balance Report, prepared annually by the International Institute for Energy Studies (IIES) affiliated with the Ministry of Petroleum of Iran (IIES, 2011), are compared in Fig. 4a. It can be seen from this figure that there is significant discrepancy between the various estimates: whereas the World Bank consistently underestimates the data, the EIA data fluctuates between the two other estimates. However, the over-estimation of Iran’s gas flaring by EIA after 2006, might be due to the inclusion

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Fig. 2. Regional gas flaring and crude oil production (Farina, 2010). Notes: (1) Gas flaring data converted to Bcf per day so it can be charted with oil. (2) To roughly convert to Bcm per year multiply by 10. (3) Flare index was constructed by taking the annual ratio MMb/d of oil produced per Bcm of gas flared converted into percentage change relative to the year 2000 (Farina, 2010).

of natural gas flaring and venting in their estimations or lack of information of EIA of the recent activities of Iran to reduce its gas flaring. In the absence of reliable measurements of the volume and composition of the associated gases, the percentage flared and the efficiency of flare (combustion efficiency), there will be great deal of uncertainties in the estimated air pollutants and greenhouse gas emissions. Fig. 4b compares Iran’s oil production based on Iran’s Hydrocarbon Balance report, OPEC, BP, and EIA. Earlier data from BP and OPEC in the period of 1960–1980, shows a great agreement. Nevertheless, in recent years there is more inconsistency between reported data from various sources. However, the uncertainties in oil production data are less significant compared with natural gas flaring.

4. Oil production and gas flaring – emission factors The first correlation between gas flaring and oil production was proposed in 1974 by Rotty. He correlated the gas flaring volume to crude oil production for two regions of US and non-US countries based on the available data set in the period of 1968–1971. Then the correlations were used to estimate the flared gas volume for each year since 1935 (Rotty, 1974). It is enlightening to relate these emissions to the amount of oil produced for each year in the respective country by calculating the emission factors as defined above (the ratio of the amount of associated gas to the barrel of oil produced). Although the emission factor is a very rough indicator of production efficiency, and it depends on many operational factors as well as on the sources of oil or flare

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Fig. 3. Comparison of global gas flaring data estimates 2000–2009 (Farina, 2010). Note: Maximum and minimum estimates based on the highest and lowest data points for each country from any of the data sets. Fig. 5. Gas flaring emission factor for the top 20 gas flaring countries in period of 2007–2011.

14000

1200000

12000

1000000

10000

800000

8000

600000

6000

400000

4000

200000

2000

0 0 1940 1950 1960 1970 1980 1990 2000 2010 2020 Fig. 6. Accumulated global oil supplied (solid line) and accumulated CO2 emission due to gas flaring (dashed line) versus production year in the period of 1950–2010. Source: Global oil supply data from Earth Policy Institute (Brown, 2010) and CO2 emission due to gas flaring from CDIAC (CDIAC, 2014).

of 1950–1970 both the oil production and CO2 emissions due to gas flaring are increased in monotonic similar trends. In the period of 1970–2010, although the oil production is increasing with almost constant slope, CO2 emissions have different increasing rates: first the slope is increased intensively, after a slight moderation again it is increased severely.

20

7000

HC Balance

18

Iran Oil Production (1000 bbl/day)

Iran gas flaring (Bcm/year)

1400000

16 14 12 10 8 6

EIA

4

GGFR

2 0 1975

HC Balance 1985

1995

(a)

2005

2015

Accumulated Global CO2 Emission from Gas Flaring (million tons)

Source: Gas flaring data from NOAA Satellite and oil production data from EIA.

Accumulated Global Oil Supplied (million bbl)

gas, as discussed in (Hassan and Kouhy, 2013), but it shows to a first approximation, how efficient the production unit is. For this purpose, oil production of all the top 20 gas flaring countries (see below) in the years of reporting the emissions is taken from EIA and then the emission factors are calculated. From Table 1 it can be seen that, for example, for oil production of 2011, emission factors range from 0.9 for Saudi Arabia to 43.9 for Uzbekistan, with an average of about 5.1 for the top 20 countries and a global average of about 4.4. Iran’s emission factor stands above the average of the top 20 emitters at about 7.3 cubic meters per barrel of oil during 2007–2011. It can also be seen that the rest of the world with the oil production of about 34.1%, contributed 15.7% to the gas global flaring. Although the high emission factor indicates, in general, that the efficiency in oil production is poor, care should be taken in interpreting this conclusion because several other factors influence gas flaring efficiencies such as the magnitude of oil production, the site of production, the composition of flare gases, the demand and market availability. Based on the data of Table 1, emission factors of the top 20 gas flaring countries are plotted for the years 2007–2011 as shown in Fig. 5. These rough emission factors can also be used to estimate emissions for individual countries for the years that no satellite data or any other measurements were available. The Carbon Dioxide Information Analysis Center (CDIAC) (CDIAC, 2014) in Tennessee has estimated global carbon dioxide emissions from flared gas for a long period of 1950–2010. A graph of cumulative CO2 emissions and oil production is shown in Fig. 6. The oil supply historical data in the same period is extracted from a report of Earth Policy Institute (Brown, 2010). This figure indicates that in the period

BP

6000

OPEC 5000

EIA

4000 3000 2000 1000 1955

1965

1975

1985

1995

2005

2015

(b)

Fig. 4. Comparison of Iran’s gas flaring (a) and oil production (b) estimates. Note: Hydrocarbon Balance data (IIES, 2011) includes only oil associated gas flaring while EIA data (EIA, 2015) includes total natural gas flaring and venting.

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5. Environmental impacts of gas flaring

5.3. Heat radiation impact

The environmental problems caused by flaring are global, regional and local (Ismail and Umukoro, 2012). The results of a recent investigation in environmental and health impacts of gas flaring in Niger Delta indicate the likely magnitude and extent of pollution across the region associated with the gas flaring process (Anejionu et al., 2015). There have been over 250 identified toxins released from flaring including carcinogens such as benzopyrene, benzene, carbon disulfide (CS2 ), carbonyl sulfide (COS) and toluene; metals such as mercury, arsenic and chromium; sour gas with H2 S and SO2 ; nitrogen oxides (NOx ); carbon dioxide (CO2 ); and methane (CH4 ) which contribute to the greenhouse gases (Ismail and Umukoro, 2012). These pollutants cause acidity, temperature increase, influence on the immediate environment, particularly on human health and plant growth.

It is known that some of the products of complete combustion, such as CO2 and H2 O, from flares contribute greatly to heat radiation experienced around flares (Ite and Ibok, 2013). In a study theoretical and empirical relationships have been briefly reviewed and summarized for determining the fraction of heat radiated from flares in proximity of a flame (Guigard et al., 2000). The applicability of these relationships to the general case is limited. The theoretical or empirical conditions for which many of these relationships are based upon are situation-specific. In addition, limited information was provided in many instances on numerous parameters that are known to influence flare heat radiation losses (e.g. stack exit velocity, crosswind velocity, aerodynamics of the flame, etc.) (Guigard et al., 2000).

5.1. Acidity impact When the combustible vapors are burnt off into the atmosphere, they in turn form acid rain especially in the humid environment of the offshore. The acid rain is corrosive in nature, and causes widespread damage to the environment, devastating to vegetation and surface water (Hassan and Kouhy, 2013; Nwankwo and Ogagarue, 2011). Acid rain causes significant impacts on freshwater, coastal and mangrove ecosystems (Ite and Ibok, 2013). Acid rain from increased SO4 2− and NO3 − concentrations is evident in the pH values that range from 4.98 to 5.15 and mean value of 5.06 (Efe, 2010). According to Efe (2010) environmental study in Nigeria, rain water acidity varied significantly and it decreases with increasing distance from gas flare sites throughout the period of study. Rapid corrosion of corrugated iron roofs (galvanized iron sheet) witnessed in the oil–producing communities have been linked to acid rain (Ite and Ibok, 2013). A study has been dedicated to compare the corrosion rate of corrugated galvanized steel roofing sheets in near flaring and non-flaring regions. A maximum weight loss of 7.62 mg was obtained at 500 m away from flare source followed by 4.23 mg at 1000 m from flare source while 1.17 mg weight loss was obtained in non-flaring zone. This shows that gas flaring has serious deteriorating effect on galvanized roofing sheet (Ovri and Iroh, 2013).

5.2. Thermal impact Anomohanran (2012) has investigated the thermal effect of gas flaring on the Ebedei community of Delta State, Nigeria. Measurements of temperature variation with distance from the flare point were obtained for both the wet and dry seasons. Results indicate that thermal pollution occurred within a distance of 2.15 km for the wet season and 2.06 km for the dry season (Anomohanran, 2012). In a study, surface temperatures, distances, latitudes and longitudes away from the flaring point were investigated for the four cardinal directions with the aid of thermometer, a fibrous meter tape and a global positioning system (GPS) (Julius, 2011). The result did not only show surface temperature elevation of about 9.1 ◦ C above the mean normal daily temperature within a radius of 210 m but a temperature gradient of 0.050 ◦ C/m (Anomohanran, 2012; Julius, 2011). In the same study, it was found important and advisable that residential buildings be situated at least 210 m away from the flare stack (Julius, 2011). High temperatures create physical, chemical, and biological conditions, harmful to human health, plant and soil micro-organisms (Anomohanran, 2012).

5.4. Photochemical effect The photochemical formation of O3 in the troposphere proceeds through the oxidation of nitric oxide (NO) to nitrogen dioxide (NO2 ) by organic-peroxy (RO2 ) or hydro-peroxy (HO2 ) radicals (EPA, 2013). The Second Texas Air Quality Field Study (TexAQS-II) aimed at obtaining a better understanding of atmospheric chemical processes was conducted in Houston in August and September 2006. The TexAQS-II Radical and Aerosol Measurement Project (TRAMP) found evidence for the importance of short-lived radical sources such as HCHO and HONO in increasing O3 productivity. During TRAMP, daytime HCHO pulses as large as 32 ppb were observed and attributed to industrial activities upwind in the Houston Ship Channel (HSC) and HCHO peaks as large as 52 ppb were detected by in situ surface monitors in the HSC. Primary HCHO produced in flares from local refineries and petrochemical facilities could increase peak O3 by ∼30 ppb (Webster et al., 2007). These concentrations are well in excess of current air quality model predictions using gas phase mechanisms alone (Sarwar et al., 2008) and multiphase processes are needed to account for these observations. 5.5. Health impact Apart from causing serious health problems such as skin cancers and lesions via dermal exposure, the ingestion of contaminated water – ‘acid rain’ can alter pH of the stomach, leach the mucous membrane of the intestinal walls and cause stomach ulcers (Ite and Ibok, 2013). Further, a greater number of people in the rural communities may be exposed to the risk of elevated levels of petroleum hydrocarbon contaminant mixtures, PAHs, and toxic metals (especially vanadium) via harvested rainwater usage (Ite and Ibok, 2013). The National Ambient Air Quality Standards (NAAQS) and the health effects of some gas flaring pollutants have been presented in Table 2. 5.6. Agriculture impact A review article illustrated the pros and cons of using bioremediation process for the remediation of petroleum contaminants in soil (Bijay Thapa et al., 2012). It is widely known that soil and sediments have become the ultimate sink for most petroleum contaminants, such as benzene, toluene, ethyl benzene, and xylenes (BTEX), aliphatic and polycyclic aromatic hydrocarbons (PAHs) (Ite and Ibok, 2013). PAHs containing from two to five fused aromatic rings are of significant concern because of the mutagenicity and carcinogenicity of several of these compounds and tendency to bioaccumulate in organic tissues due to their lipophilic character and electrochemical stability (Ite and Ibok, 2013).

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Table 2 National Ambient Air Quality Standards (NAAQS) and the health effects of gas flaring pollutants (Vanos et al., 2013; Argo, 2002). Pollutant

Acceptable level

Health effect

Nitrogen oxides (NOx ) Carbon monoxide (CO) Sulfur oxides (SO2 ) Benzene Toluene

32 ppb (mean annual) 5 ppm (mean daily) 57 ppb (mean daily) 0.096 ␮g/m3 (annual average) 120 ng/m3 (mean daily)

Xylenes

0.12 ng/m3 (mean daily)

Styrene Naphthalene

Not reported 96 ng/m3 (mean daily)

Black carbon Formaldehyde

3.5 mg/m3 (OSHA, 2012) (8 h average) 0.75 ppm (OSHA, 2011) (8 h average)

Lung irritation, decrease lung function, increase susceptibility to allergens for asthmatics Headache, nausea, weakness, potential long-term health effects Adverse effects on respiratory systems of humans due to irritation and airway obstruction Leukemia, aplastic anemia, pancytopenia, leukocytes, thrombocytes Potent central nervous system toxicant leading to narcosis, in coordination, emotional liability, and subjective symptoms such as headache and fatigue. Unequivocal developmental toxins, leading to delayed development, decreased fetal body weights and altered enzyme activities Irritant of the skin, eyes, and mucous membranes and a central nervous system depressant Destroying the membrane of the red blood cells with the liberation of hemoglobin, irritating the eyes Caused to accumulation of dust in pulmonary system and pneumoconiosis (OSHA, 2012) Irritation of lungs and mucous membranes, cause to naso/pharyngeal cancers and possibly leukemia (EPA, 2007)

It is known that thermal pollution from gas flares affects the microbial populations, which participate in organic matter decomposition and nitrogen formation process resulting in a decline in organic matter and total nitrogen, as well as microbial populations, humid (top soil) formation, nutrient availability and soil fertility. Therefore, gas flaring impacts adversely on soil fertility and biogeochemical nutrient cycles and the negative effects of physio–chemical properties of the soil subsequently impact on some crops due to modification of the microclimate in the region (Ite and Ibok, 2013). The toxicity of contaminant mixtures from gas flare and vent systems could affect some aquatic organisms by changing their phylogenetic position and reduction in their relative sensitivity as the intensity of gas flares increases (Ite and Ibok, 2013). It was observed that air, soil and leaf temperatures increased and relative humidity of the air decreased within 110 m from the flare sites (Isichei and Sanford, 1976). It is recommended that agricultural crops, which respond negatively to high temperature variation, should not be planted in this area (Anomohanran, 2012). Odjugo and Osemwenkhae (2009) have reported the impact of natural gas flaring on microclimate and maize yield in the Niger Delta, using Ovade flare site as a case study. The results show that with rise in air and soil temperatures of the flare site, relative humidity, soil moisture and all the soil chemical parameters decrease toward the flare. The induced microclimatic condition reduced the yield of maize such that maize production is not economically viable within 2 km from the flare site. 6. Techno-economic constraints on reduction of flare emissions Farina (2010) has discussed in detail the techno-economic constraints and the lack of policy and regulatory frameworks for gas flaring reduction in different countries. In Nigeria, a multi-decade legacy of flaring has been a flashpoint for conflict in the Niger Delta region. Repeated postponements of government deadlines, the most recent in 2008, for a phase out of gas flaring have diminished expectations for a lasting solution. The challenge in Nigeria, and in other parts of West Africa, is to enact effective policies that simultaneously build a dynamic energy sector, foster local economic development, improve security, and enhance government commitment to regulation and enforcement, all while finding a way to develop new infrastructure to connect dispersed sites. In this region, external financing solutions, expansion of public-private partnerships and political will to advance policy reform will be critical to drive flare reductions (Farina, 2010). In some cases, there are high levels of contaminates, such as hydrogen sulfide and heavy liquids, within natural gas that drive up gas gathering and processing costs. If gas is sold at fixed prices

in the marketplace well below the costs of associated gas gathering it creates a dilemma for gas producers. As a result, it is not uncommon to see development of “sweeter” less costly non-associated gas while “sour” associated gas is flared, despite the existence of nearby areas with a strong demand for additional gas (Farina, 2010). In the Middle East, domestic pricing policies distort the economics of gas flaring projects especially at older brownfield sites. In places such as Iraq and Iran, where physical conditions should support gas infrastructure construction, political/economic/technological issues and security concerns have delayed the needed investments. In these regions it is the governments that must lead; recognizing the negative externalities associated with flaring and incorporating associated gas strategies in their oil industry policies (Farina, 2010). In the special case of Iran, the law and regulatory measures will further be presented in Section 10.5. It will be shown in the following sections that the gas pricing policy is perhaps one of the major causes of delays in implementation of gas flaring reduction projects in Iran. In offshore platforms there are tight weight constraints, and installing additional processing kit can add significant weight and cost. Offshore flaring is far more complex – unless it is designed into the platform from the start as there is little space to work and so any changes to the layout of the platform will have a major impact on the operations. This basically means that for offshore projects, unless the flare reduction is designed from the start, it is unlikely to happen later, unless part of a major overhauls (CDM PDD, 2006). Depending on the region, proven technologies such as distributed power generation, large-scale efficient commercial power generation, re-injection, gathering and processing, liquefied natural gas (LNG) and micro gas-to-liquids (GTL) will all have their place. The perception that associated gas is not worth the effort needs to be challenged. Beyond national borders, the role of the international community will be to accelerate the process, acting as a catalyst for change to achieve practical outcomes that create value, generate social benefits, and increase environmental protection (Farina, 2010). One of the critical flare gas issues from a technology perspective is how to justify processing expense for small volumes of lowpressure gas that decline quickly relative to traditional gas fields. The Russian Academy of Sciences study estimates associated gas processing costs at $47 per Mcm, excluding gathering and compression charges. Estimates from several sources conclude that basic gas processing costs for rich associated gas range between $40 and $80 per Mcm ($0.90 to $2.00 per MMBtu). This estimate assumes a basic gas-processing package of compression to 30 bar (∼435 psi), dehydration, and refrigeration (chilling) to create lean gas and a raw NGL mix. The analysis shows that for traditional systems, per-unit cost starts to escalate rapidly as the size of gas stream

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Table 3 Commercial technologies for associated and non-associated gas conversion. Technology

Market maturitya

Successful cases

Promoted by

Ref.

Re-injection CNG LNG Gas to GTL Gas to power Gas to chemicals (Ammonia, methanol, DME)

Commercial Not commercial Commercial Near to Commercial Commercial Commercial

Kazakhstan – Soyo, Angola (since 2010) Pearl GTL, Qatar (since 2012) Canada Petrochemicals in Persian Gulf

GE technology – GGFR project Shell and Qatar Petroleum – –

Farina (2010) Buzco-Guven et al. (2010) World Bank (2013) Buzco-Guven et al. (2010) Buzco-Guven et al. (2010) Buzco-Guven et al. (2010)

a

Commerciality of a technology depends on many factors such as technology availability, marketing, alternatives and economical factors.

decreases. Lower gas flow equals higher costs. Project specific processing costs range dramatically with the gas composition, size of the plant, and level of gas treatment for contaminates (Farina, 2010). In summary, significant amount of associated gases are still flared globally due to economic constraints, lack of policy and regulatory frameworks, domestic fuel price subsidies, and technical constraints like gas impurities and the degree of sourness, gas infrastructure construction, gas flow and its fluctuations. High levels of contaminates, such as hydrogen sulfide, increase the associated gas gathering and processing costs, so that the “sweeter” less costly non-associated gas is often preferred while “sour” associated gas is flared, despite the existence of nearby areas with a strong demand for additional gas. The gas price also has a critical role in the flare gas recovery deployment, which may cause dilemma for the associated gas producers as mentioned above (Farina, 2010). The dependence of associated gas volume to oil extraction keeps gas infrastructure investments in synch with oil developments. All wells producing with a gas-to-oil recovery (GOR) greater than 3000 m3 /m3 at any time during the life of the well must be shut-in or so that the gas is saved, or for any sites flaring or venting combined volumes greater than 900 m3 /day, a review of conservation economics must be done at least once every 12 months (Odjugo and Osemwenkhae, 2009). This is a dominant challenge in some regions, especially in the Americas and parts of Asia (Farina, 2010). In places like the Middle East, where physical conditions should support gas infrastructure construction, political/economic/technological issues and security concerns have delayed the needed investments. In Iran, the government should lead, recognizing the negative externalities associated with flaring, by accelerating the implementation of the already planned gas flaring projects and improving the pricing policies of the associated gases. 7. Gas flaring reduction technologies Various proven gas utilization technologies for different applications are addressed in World Bank Report (Bank, 2004). These technologies are summarized in Table 3 and described in detail below. 7.1. Re-injection Re-injection is a commonly used method to preserve gas for future use or to increase the efficiency of the oil production process. The technology involves the installation of a gas compressor to re-pressurize areas of low-pressure formation gas, enhancing oil production. As an alternative to gas compressors, multiphase pump systems – in which oil and gas can flow together – have a smaller equipment size and allow determination of the flow characteristics without the need to separate oil and gas (Buzco-Guven et al., 2010). Re-injection or recycle is often applied offshore in order to boost oil recovery by maintaining reservoir pressure and simultaneously reduce or eliminate the need for gas transportation facilities. This is still an attractive option for small volumes of associated gas;

it is aimed at utilizing small volumes of gas, which previously were flared because of the relatively small volume during production. It is often used in cases where investment in processing or export infrastructure would render the prospect uneconomical. However, for reservoirs with substantial gas reserves, re-injection is often considered uneconomic (Odumugbo, 2010). Since 2000, the deployment of this technology in Kazakhstan the gas re-injection has prevented annually more than 49 million tons of CO2 from being released into the atmosphere (Farina, 2010). A successful reinjection project at an oil field in Southeast Asia aims to reduce GHG emissions by 2.65 million tons of CO2 eq by conserving the gas from the oil field to be vented or flared (Buzco-Guven et al., 2010). In Iran around 31.45 MMscmd natural gas is re-injected (see Table 8) (IIES, 2011) and the best example is Darkhoin project, which was completed in 2010 in which about 7 MMscmd is re-injected. There are some other projects under construction like Bibi-Hakimeh and Labsefid (Personal Communication, 2014). 7.2. Power generation This technology is an option for meeting the nearby electricity demand or export the electricity to the grid. In Argentina, aeroderivative gas turbine burns 0.45 million cubic meters per day of previously flared low Btu gas to generate about 40 MW of power (Farina, 2010). 7.3. Pipeline natural gas (PNG) PNG is the principal and most convenient method of transporting gas; either from an offshore location to onshore for processing or to interface with existing distribution grids. It is also used for transportation of export gas. Nevertheless, for offshore transport of natural gas, pipelines become challenging as the water depth and the transporting distance increase. The economics of gas transportation through pipeline is a function of distance (Odumugbo, 2010). Parker has reported cost functions for natural gas transmission pipeline (Parker, 2004). Gas to pipelines are not flexible as the gas will leave the source and arrive at its destination. Once the pipeline diameter is decided the quantities of gas that can be delivered is fixed by the pressures, although an increase in the maximum quantity can be achieved by adding compressors along the line, extra pipe in the form of loops or by increasing the average pipeline pressure. Pipeline pressures are normally 700–1100 psig (although 4000 psig lines are in operation) depending on the material of construction and the age of the pipe. Installation of pipeline costs currently, on average, 1–5 million USD per mile, sometimes even higher, depending on the terrain (such as for onshore, mountains or for offshore, seabed flatness and depth) plus compressor stations (Thomas and Dawe, 2003). 7.4. Liquefied petroleum gas (LPG) This technology is an alternative way of utilizing associated gas because of its easy storage and transport to local markets,

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and due to the higher percentage of propane and butane in associated gas compression compared to non-associated gas. Before extracting the liquefied petroleum gases, associated gas must first be treated for removal of impurities including water vapor, CO2 , mercury vapor and H2 S. Conventional LPG processes treat the whole gas stream before extracting the LPG content. These processes are not economical and practical for associated gas produced in much lower volumes and have a lower pressure than nonassociated gas from gas wells. Therefore, some companies have developed technologies to treat only the recovered LPG content of the associated gas to remove the contaminants and thus to reduce the plant size and associated capital costs (Buzco-Guven et al., 2010). 7.5. Liquefied natural gas (LNG) LNG technology uses a straightforward refrigeration process. The gas is pre-treated for impurities such as sulfur, CO2 , water, and other contaminants, transformed into liquid by being cooled to −162 ◦ C, and stored until it is shipped onboard LNG tankers. LNG has a volume ∼1/600 that of gas at room temperature. After transport to a receiving terminal, the liquefied gas is re-gasified for use in gas markets (Buzco-Guven et al., 2010; Thomas and Dawe, 2003). A new LNG technology concept that has yet to be developed and proven commercially is called floating LNG (FLNG). This process is a combination of conventional LNG and floating deepwater offshore production technologies. The combined FLNG vessels will contain liquefaction facilities onboard, and can be moved to small and remote oil fields easily, without having the need to build large, new facilities at each location. This concept is largely advocated by Shell and the first commercial applications are likely to be in Australia at remote Browse Basin gas fields (Marcano and Cheung, 2007). The relatively low volume of gas associated with oil production may still fall below the commerciality threshold of FLNG, which requires inputs of about 10 MMcmd (Farina, 2010; Buzco-Guven et al., 2010). Some of already operating small-scale liquefaction plants are: Clean Energy, 100,000 gallons/day in Texas, USA; Naturgass Vest, 120 tons/day in Bergen, Norway; Xinao LNG Plant, 170,000 scmd flared gas in Weizhou Island, China (Cornitius, 2006). LNG plants are large scale, long contract (∼20 years or more) and require large >85 Bscm gas reserves and ∼ 1 billion USD investment for a train processing around 14 MMscmd (Thomas and Dawe, 2003). 7.6. Compressed natural gas (CNG) CNG technology is the compression of natural gas to a much lower volume (1/1200 of the original volume) at pressure between 8300 and 30,000 kPa. CNG is stored and transported in cylinders (Buzco-Guven et al., 2010). There are a number of advantages of CNG when compared to LNG, which have created the very strong interest in CNG that exists today. They are: (1) no need for liquefaction or re-gasification; (2) the gas does not need to be cleaned to the same extent as it is necessary for LNG pre-processing; (3) the CNG container may be made of fine grain normalized steel, such as API 5L pipeline quality steel, rather than the significantly more expensive high nickel steel, aluminum or stainless steel needed to carry cryogenic LNG (Rynn et al., 2005). This technology has the potential to become the preferred method of utilizing associated gas in offshore platforms where building pipeline or LNG plants are not economical and practical (Odumugbo, 2010). Since CNG is transportable, and therefore easily re-deployable, it can be used in fields with relatively short production horizons. Trans Ocean Gas is in the process of commercializing its CNG transport technology. Developments in CNG technology are

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supported by Statoil, TransCanada, and ExxonMobil (Buzco-Guven et al., 2010). 7.7. Natural gas hydrates (NGH) NGH is crystallized natural gas, a solid material in an ice state and chemically stable at −20 ◦ C. The stabilizing temperature is considerably higher than that the LNG temperature of −162 ◦ C, which leads to lower capital, transportation, and storage costs. However, NGH is far less dense than LNG and quantity of gas transportable in hydrate form is correspondingly lower than LNG technology. NGH as a method to utilize associated gas is still in the research phase, but Mitsui and Mitsubishi, the BG Group, and Marathon Oil are leading the efforts to develop gas-to-solid technology (Marcano and Cheung, 2007). 7.8. Gas-to-liquid (GTL) GTL technology is a chemical process that converts methane gas into transportation fuels, such as gasoline or diesel fuels (Fleisch, 2014). GTL technology is still in development since it has not been economically feasible and has involved more technical risks. A world scale GTL plant can convert 8.5 MMscmd of gas into 30,000 bpd of diesel or gasoline (Fleisch, 2014). Over the last few years, mini GTL technologies have been developed to monetize smaller volumes of gas (less than 0.7 MMscmd) and thereby offer opportunities to extinguish flares (Fleisch, 2014). Now, Oberon Fuels, Velocys and Compact GTL are on the brink of multiple commercial plants (Fleisch, 2014). Fleisch has reviewed over 24 companies of mini GTL technologies available today (Fleisch, 2014). Qatar is a leader in the world with the most GTL projects, which produce 330,000–500,000 bbl/day, followed by Australia with 120,000 bbl/day (Buzco-Guven et al., 2010). The Pearl gas-toliquids (GTL) plant, jointly owned by Qatar Petroleum and Shell, located in Ras Laffan Industrial City, sold its first commercial shipment of GTL gasoil in June 2011. The second train of the plant became operational in late 2011 and the plant was scheduled to reach full capacity by mid-2012. Once fully operational, Pearl GTL is designed to consume some 45 MMscmd from the North Field, which will be processed to deliver an expected 120,000 bpd of condensate, LPG and ethane and an expected 140,000 bpd of GTL products (Wood et al., 2012). Escravos, Nigeria developed by Chevron Nigeria Limited, NNPC and Sasol, was expected to start up by mid-2014 and will use 15% of total flaring to produce GTL products (diesel ∼70% and naphtha ∼30%) with capacity of 34,000 bbl/d from two trains, the feed gas required to support the production capacity of the plant is around 9.6 MMscmd (Buzco-Guven et al., 2010; Odumugbo, 2010). 7.9. Methanol and ammonia production Methane in natural gas and associated gas can also be converted to methanol. Methanol is further used to produce dimethyl ether (DME) and olefins such as ethylene and propylene in simple reactor systems, conventional operating conditions and commercial catalysts (Odumugbo, 2010). Lurgi’s Mega Methanol, MTP, and Mega Syn technologies and Topsoe’s DME process provide cost-effective and large economy-of-scale solutions to gas conversion. Methane in associated gas can also be converted to ammonia via the Haber process to produce nitrogen fertilizers. This method is quite common in the Persian Gulf oil-producing countries (Buzco-Guven et al., 2010). 7.10. Comparison of technology options Factors, including capital investment, technology risks, domestic market and its infrastructure, and political environment,

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companies’ strategies, compete for decision making. These factors may make a technology practical to be commissioned in somewhere while applying the same technology may not be reasonable in somewhere else. Although, a general comparison of all alternatives is difficult to make, a case-by-case analysis is commended for the best action selection. In this manner, IEA has suggested some tips. In the case of relatively short distances to markets and low gas volumes, electricity generation or pipeline transport of the gas might be economical alternatives to flaring. If the gas volumes are higher than 10 Mscmd and distances to markets are greater than 2000 km, there are some other options to utilize the gas, including LNG or GTL plants, and transporting the liquids produced via tankers to the market locations. Although LNG has slightly lower operating costs than GTL, the overall production cost for LNG and GTL products for the same amount of natural gas is quite similar (on the order of 2.5 billion USD) (Lichun et al., 2008). The pricing for LNG products requires long-term contracts. Therefore, in the end, the decision to install either an LNG or GTL unit will be dependent on other factors such as local market needs, available resources, and companies’ and governments’ priorities, etc. (Zhang and Pang, 2005). Dong et al. (2008) compared GTL and LNG then concluded on the commercial viability of GTL, and claimed that while a GTL facility is more complex, less efficient and more expensive than an LNG facility, their end-to-end supply chains are quite comparable and, thus, a decision to invest in either is challenging. Khalilpour and Karimi’s (2012) study suggested GTL as the best option for large reservoirs and distant markets; however, an NG utilization method for any field will depend on both technical and economic factors. Small volumes of intermittent gas are not economically attractive to the major gas sellers, particularly for LNG facilities or pipelines. For the smaller markets, e.g. islands where pipelines or LNG are not feasible, NGH and CNG can be economic potential transport methods. There could be options for handling niche markets for gas reserves stranded (no market) and for associated gas (on- or off-shore) which cannot be flared or re-injected, or for small reservoirs which cannot otherwise be economically exploited (Thomas and Dawe, 2003). The strength of subsea gas pipelines is associated with transportation of large gas volumes fairly short distances to the market. For quantities less than some 5.7 MMscmd this alternative rapidly loses ground to other alternatives such as CNG and Electricity conversion (Eriksen et al., 2002). Transportation of natural gas as hydrate or CNG is believed feasible at costs less than for LNG and where pipelines are not possible. The competitive advantage of NGH or CNG over the other non-pipeline transport processes is that they are intrinsically simple, so should be much easier to implement at lower capital costs, provided that economically attractive market opportunities can be negotiated to the gas seller (Thomas and Dawe, 2003). LNG, CNG and GTL technologies’ capital and operating cost functions are reported and compared by Khalilpour and Karimi (2012). Alternative technologies of PNG (pipeline natural gas), LNG, CNG and NGH have been investigated for transporting 100 MMscmd natural gas from port of Assaluyeh in the south of Iran in the Persian Gulf area to potential markets. The results indicate that for short distances (up to 2700 km), PNG is the best option. In this range, CNG has a lower production cost than LNG and NGH but, the production cost of CNG versus distance increases sharply and for distanced higher than 2700 km, LNG becomes more attractive. For medium distance range (from 2700 to 7600 km) still PNG has the lowest production cost. LNG becomes the best option for distances larger than 7600 km (Najibi et al., 2009).

8. Best practice cases In this section some of the successful projects and best practice options will be reviewed. Despite increasing levels of oil production, Norway reduced gas flaring and venting significantly by widely using incentives and penalties, such as a CO2 tax on emissions to encourage oil producers to reduce gas flaring volumes (Buzco-Guven et al., 2010). In 2007, the total associated gas production for Canada was 23.7 Bcm, 94% of which was utilized in domestic heating and power generation as well as industrial and commercial use. The associated gas is re-injected in some oil fields, and is also used as fuel in industrial processes, and in oil field operations. The well-developed pipeline and transportation infrastructure in Canada and United States also allows distributing the associated gas to North America’s gas network (Buzco-Guven et al., 2010). Although greenhouse gas emissions are not regulated in United States, other constituents of associated gas are strictly regulated by Environmental Protection Agency (EPA). The EPA requires companies to report gas flaring volumes and regulates their emissions from flaring activities. Onshore and offshore producers of oil and associated gas are required to manage associated gas through transportation to a market, power generation, or re-injection (Buzco-Guven et al., 2010). Chevron in Angola has several associated gas management projects. The Flare and Relief Modification (FARM) project, along with the offshore Gas Processing Platform and Cabinda Gas Plant, upgrades and modifies the flare gas and relief systems on 14 offshore facilities, processes offshore natural gas liquids, and produces LPG for export by using floating production, storage, and offloading vessels. The project will eliminate 0.7 MMscmd of flared gas (Buzco-Guven et al., 2010). The AMAK project in Iran, started the most extensive environmental project implemented by the National Iranian South Oil Company in February 2005, to collect associated gas from 7 fields of the reservoirs in Ahwaz in south-west Iran (Ab-Teymour, Mansuri, Marun, Ahwaz and Kupal). The project was so big that they needed to construct seven sour gas compressors, one acid gas compressor, a sweetening plant, 280 km long gas pipeline and 95 km of power lines. As a result of the implementation of this large project, emission of 6.8 MMscmd of sour gas was prevented and the gas was utilized (Andersen et al., 2012). For more information see Section 10.4.1. The most common methodology for utilizing associated gas in Iran is to produce liquefied petroleum gas (LPG) in NGL Plants. Many NGL plants in different parts of the country utilize gathered associated gas from different oil fields for producing LPG. Also in the last decade reinjection has been common in some projects for the purpose of enhance oil recovery (EOR). Although in recent years some projects for power generation and GTL have been proposed by private companies in Iran, but they are still under study and have not been advanced to design and implementation phase. LNG projects to transform natural gas to liquid are not common for associated gas utilization in Iran (Personal Communication, 2014). For details refer to Table 9 in Section 10.4.

9. CDM projects for gas flaring reduction Under the United Nations Framework Convention on Climate Change (UNFCCC) and its Kyoto Protocol, gas flaring could be registered as a Clean Development Mechanism (CDM) for greenhouse emissions reduction. The CDM program has only sparingly been used in associated gas flaring projects despite its great potential. According to a recent report prepared by the Norwegian University of Science and Technology (Andersen et al., 2012), global emissions from gas flaring alone stand for more than one-half of the

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annual Certified Emissions Reductions (624 million tons CO2 ) currently issued under CDM. This is a significant proportion because most gas flaring projects are large-scale projects and thus the total greenhouse gas reduction through gas flaring projects is equivalent to many other small-scale registered CDM projects. There are only five approved methodologies for gas flaring CDM projects: recovery and utilization of vented or flared gas (AM0009), flared gas to energy or feedstock (AM0037), waste gas to power generation (AM0074), and recovery and delivery of flared gas to specific end-users (AM0077) waste gas to power generation (ACM0004) (CDM Methodology Booklet, 2012). According to Gouvello (2011), 14 out of 15 different gas flaring projects validated or registered as CDM project in UNFCCC Secretariat, are in AM0009 methodology and only one project is in AM0037 methodology (See Table 4). Based on the registered annual CO2 emission reduction of each project, and by assuming that all projects have been implemented, overall 69,274 Mtons CO2 emission has been reduced by the end of 2012 (Gouvello, 2011). According to UNFCCC website, Turkmenistan, Kuwait, Iraq and Nigeria have proposed five other large scale flare gas recovery project design documents (PDD) in 2012, which totally can reduce annually 9 Mtons CO2 emissions (UNFCCC, 2014). Iran’s only registered CDM project is the Soroosh & Nowrooz Early Gas Gathering and Utilization project as part of Kharg and Behregansar project discussed in more details in Section 10.4.2. According to Soroosh & Nowrooz project design document (PDD), the annual average emission reduction over the crediting period was estimated to be 463,122 tons of CO2 eq. Total capital infrastructure utilized for this project is estimated at 118.2 million USD (CDM PDD, 2006). This project has been commissioned in 2010 with around 0.08 MMscmd gas transporting to Kharg Island, which was increased to 0.4 MMscmd in 2011. The first monitoring report of this project led to issuing 202,000 certified emission reduction (CER) (IIES, 2011). However, due to several financial and technical constraints, the estimated emissions reduction of 463,122 tons of CO2 eq as anticipated in the PDD was not realized as can be seen from the last row, item 16 of Table 4. To receive CDM financing, project developers not only need to provide detailed methodologies to demonstrate baselines and the volumes of gas flaring reduced, they also need to demonstrate that flare gas reduction projects would not move ahead without carbon financing, the so-called “additionality” test. This requires capabilities and monitoring that are often unavailable in some developing nations (Farina, 2010). Unfortunately, the sharp decline in the carbon price in the CDM market as a result of the decisions of the Conference of Parties (COP) of the UNFCCC and the Kyoto Protocol has caused a very low market for new CDM projects, especially the large-scale gas flaring projects.

10. Gas flaring in Iran 10.1. Historical background Oil exploration and production in the world dates back to over 150 years ago with more than two million wells around the world; many of the early wells turned out to be dry (History, 2014). The first oil exploration and drilling operations for oil in Iran were started more than a century ago by William D’Arcy when the concession made on May 28th 1901 marked the foundation of Iran’s oil industry. Since the US oil industry came to existence in 1859, several concessions were granted in Iran for crude oil production. Numerous drilling operations were carried out in the west and southwest parts of the country without satisfactory results, until about 1905 when the first major oil production began in Masjed

13

Soleiman region in southwest of Iran (NIOC, 2014). Since then the drilling and oil production in Iran were carried out by international oil consortiums until the National Iranian Oil Company (NIOC) was established in 1951 that has since been directing and making policies for exploration, drilling, production, research and development, refining, distribution and export of oil, gas, petroleum products. NIOC, with a vast amount of oil and gas resources, is one of the world’s largest oil companies. At the present time, it is estimated that the company holds 156.53 billion barrels of liquid hydrocarbons and 33.79 trillion cubic meters of natural gas (Operated by the National Iranian Gas Company – NIGC). NIOC consists of seventeen production companies, eight technical service companies, seven managements, six divisions (administrative units) and five organizational units (NIOC, 2014). In general, global gas flaring data is scarcely available before 1950. For Iran gas flaring data for pre-nationalization period (1951) from Iranian oil fields is also not available, particularly that oil production was carried out mostly by the international oil consortiums with no central national administration for oil production. Indeed, Iran has officially reported gas flaring data only from 2001 onward. However, gas flaring data for Iran is available since 1980 based on the US EIA and since 1995 based on GGFR of the World Bank, although the data reported by EIA might have been estimated data and independent from the official data reported by Iran. As discussed above, oil production can be used to estimate the amount of gas flared for each year. Oil production and flaring data for Iran from 1980 to 2012 are available from EIA (EIA, 2015). In CDIAC data bank, a statistical data set for gas-flaring-related CO2 emissions in Iran is reported for the period of 1955–2008 (CDIAC, 2014). 10.2. Gas flaring sources in Iran As mentioned in the Introduction, gas flaring is practiced not only in oil production, but it is also in natural gas production, in oil and gas refineries and in petrochemical plants. It suffices to mention that in addition to the four major oil companies listed below, there are large gas flaring emission sources including 9 petroleum refineries, 18 gas refineries, 39 petrochemical plants which have gas flaring operations (IIES, 2011). Although the focus of this paper is on the gas flaring in oil production in Iran, the importance and contribution of other sources such as natural gas production and refineries should not be overlooked. For example, Tabriz Oil Refinery in northwestern Iran flares 22.5 million cubic meters annually (Zadakbar et al., 2008), and Farashband gas refinery near Shiraz flares 40 million cubic meters (mcm) annually (Rahimpour and Jokar, 2012) compared to 17.6 Bcm flared gas in Iran in 2012 (IIES, 2011). These amounts are roughly, 0.13% and 0.22% of Iran’s associated gas flaring, respectively for the same year. South Pars Gas Refineries in Assaluyeh in the northern coast of Persian Gulf in south Iran are other significant sources of gas flaring. However, there exists great uncertainty in the amount of emission from these sources. In one study the total gas flaring in 8 phases of South Pars Gas Refineries has been reported to be around 1.4 MMscmd (Davoudi et al., 2013). However, by personal communication with National Iranian Oil Company it was found that the annual average of gas flaring volume is around 2.83 MMscmd for 10 active phases of South Pars gas refineries roughly 4.6% of total flared gas by National Iranian Oil Company (NIOC). In another source, the amount of natural gas flared in the South Pars Oil and Gas Zone was estimated to be around 3.5 million cubic meters per day in October 2013 (Ayaronline, 2013). It seems that gas flaring volume of 3–3.5 MMscmd is more realistic and the lower reported volume could be due to estimation method which may not reflect gas flaring during shutdowns or other technical considerations.

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Table 4 Gas flaring CDM projects in validation and registration stages (Gouvello, 2011).

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16a a

Title

Host country

Annual ktonCO2

Credit start

2012 ktonCO2

Use of recovered gas for methanol production Flare gas recovery project at Hazira Gas Process Comp, (ONGC) Gas flaring reduction project at Cauvery Asset, (ONGC) Gas flaring reduction project at Mumbai High, (ONGC) Gas flaring reduction project at Ankleshwar Asset, (ONGC) Gas flaring reduction project at Assam Asset, (ONGC) Gas flaring reduction project at Rajamundry Asset, (ONGC) Gas flaring reduction project at Neelam and Heera Asset, (ONGC) Flare gas recovery project at Uran plant, (ONGC) Limited Gas flaring reduction project at Mehsana Asset, (ONGC) Gas flaring reduction project at Ahmedabad Asset, (ONGC) Recovery of associated gas Kwale oil–gas process plant, Nigeria The Ovade Ogharefe Gas Capture and Processing Project Al-Shaheen Oil Field Gas Recovery and Utilization Project Rang Dong oil filed associated gas recovery and utilization (NM26) Soroosh & Nowrooz Early Gas Gathering and Utilization Project (S&N project)

Equat. Guinea India India India India India India India India India India Nigeria Nigeria Qatar Vietnam Iran

2356.03 73.58 33.36 201.34 136.64 21.12 26.85 109.46 96.35 16.74 13.04 1496.93 2531.7 1457.81 677 202

1-May-01 1-Sep-06 1-Sep-06 1-Sep-06 1-Sep-06 1-Sep-06 1-Sep-06 1-Sep-06 1-Sep-06 1-Sep-06 1-Sep-06 16-Oct-06 1-Jan-07 1-Jan-07 1-Dec-01 3-Nov-10

23,560 466 211 1274 865 134 170 693 610 106 130 10,521 14,505 9120 6910 –

This project has not been included in Gouvello (2011) and was added by the authors.

Fig. 7. Iranian petroleum facilities: oil and gas fields and refineries (a) from Wikipedia (2014) and Iran’s flares map (b) from Google Earth based on NOAA data.

Emission of air pollutants and greenhouse gases from this important natural gas production and refining complex and its associated petrochemical plants were estimated in a comprehensive study in 2006 (Soltanieh, 2006). Considering significant expansion of facilities in this region since that date, update of detailed information is not available. However, since the emphasis of this paper is on the gas flaring from oil production, the focus will be on this sector. There are four main oil production companies in Iran which operate in different zones: • • • •

National Iranian South Oil Company (NISOC) Iranian Central Oil Fields Company (ICOFC) Iranian Offshore Oil Company (IOOC) Arvandan Oil and Gas Company (AOGC)

The map of Iran in Fig. 7a shows the location of these oil production zones; one is offshore in the Persian Gulf and the other three are onshore. Fig. 7b is extracted from Google Earth which shows

all gas flaring locations in Iran. In the top 100 flare list, Iran has 13 flares mostly in offshore regions (NOAA, 2014). The contribution of each of these companies to oil production and the associated gas flaring in 2011 in Iran is presented in Fig. 8 and Table 5 below. It can be seen that more than 75% of oil production is by the National Iranian South Oil Company and the least is by Arvandan Oil and Gas Company. It is interesting to compare the gas flaring from these four zones of oil production in the same year (2011). According to Table 5, the gas flaring in the four zones in 2011 was, 12.68, 3.98, 20.35 and 0.46 million cubic meters per day, respectively. The relevant emission factors are also shown in Table 5. It can be seen that Iran Offshore Oil Company had the highest emission factor (33.29 cubic meters of gas per barrel of oil) whereas the Arvandan Oil and Gas Company had the lowest (2.97 cubic meters of gas per barrel of oil) (IIES, 2011). Iran’s oil production, associated gas flaring rate and emission factors for the period 2007–2011 are shown in Table 6 and depicted in Fig. 9. The gas flaring volume fluctuations compared to oil production is considered to be normal in most oil production facilities

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Table 5 Iranian oil companies’ oil production, gas flaring volume and emission factor in 2011 (IIES, 2011). Company

Gas flaring volume (MMscmd)

Oil prod. vol. (1000 bbl/day)

Emission Factor (scm/bbl)

National Iranian South Oil Company Iranian Central Oil Fields Company Iranian Offshore Oil Company Arvandan Oil and Gas Company

12.68 3.98 20.35 0.46

2977.59 159.72 611.39 154.94

4.26 24.92 33.28 2.97

Table 6 Oil production, associated gas flaring and emission factors for Iran during 2001–2011 (IIES, 2011).

Oil production (1000 bbl/day) Flared gas (MMscmd) Emission factor (scm/bbl oil)

2001

2002

2003

2004

2005

2006

3706 34.48 9.30

3637 31.5 8.66

3983 38.08 9.56

3996.2 34.88 8.73

4021.6 38.21 9.50

4056.9 38.96 9.60

Oil production (1000 bbl/day) Flared gas (MMscmd) Emission factor (scm/bbl oil)

2007

2008

2009

2010

2011

4103.6 39.53 9.63

4016.6 40.32 10.04

3927.43 41.56 10.58

3942.42 37.24 9.45

3903.7 37.46 9.60

Bold texts and numbers signify the importance and focal areas relevant to this paper.

have not been functioning well or has been out of service for any reason. • The pressure drop in the oil wells can cause some fluctuations in the gas to oil ratio which is a common and known behavior in oil extraction. • The other reason may be due to the overall oil extraction planning among the different oil companies of NIOC, i.e. the share of each oil field in total production level. Since the flared gas volume depends of the fields, this fluctuation may be observed. For example, oil production in offshore sites (IOOC) cause higher gas flaring than onshore facilities (such as NISOC) which is due to the lack of gas gathering facilities in offshore fields.

1%

34%

54% 11% National Iranian South Oil Company Iranian Central Oil Fields Company Iranian Offshore Oil Company Arvandan Oil and Gas Company Fig. 8. Share of the associated gas flaring in the four Iranian oil companies in 2011 (IIES, 2011).

however, the following reasons are suggested for gas flared volume fluctuation between 2003–2004 and 2009–2010:

44

4.1

42 40

4

38 3.9 36 3.8

34 Oil Production Volume

3.7

Gas Flaring Volume

3.6 2000

2002

2004

2006

(a)

2008

2010

32 30 2012

12 Emission Factor (cubic meters of flared gas per bbl produced oil)

4.2

Gas Flaring Volume (million cubic meters per day)

Oil Production (million bbl/day)

• It may be related to the operation of collecting and processing facilities of associated gas. This means that the facility might

Iran’s gas flaring-related carbon dioxide emission share from total national CO2 emission is shown in Fig. 10. This figure has been prepared from the data source of CDIAC for a long period of 1965–2008 (CDIAC, 2014). This figure indicates that the percentage of gas flaring-related CO2 emission compared to the total CO2 emission has had a decreasing trend during 1965–2008, with a minimum in 1998, and it remained relatively constant during 1990–2008 at a level of about 10–7%. This is despite the fact that the absolute value of Iran’s gas flaring has increased in recent years as shows in Fig. 4b. This may be due to the fact that carbon dioxide emissions from other sectors have been risen at a much greater rate than in gas flaring section.

11 10 9 8 7 6 2000

2002

2004

2006

2008

2010

2012

(b)

Fig. 9. Daily oil production, gas flaring (a), and gas flaring emission factor (b) for Iran during 2001–2011 based on IIES data (IIES, 2011).

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Table 7 Oil production, gas flaring volume and emission factor for Iran in the period of 1980–2012 based on EIA data (EIA, 2015). Year

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

Gas flaring (Bcm) Oil prod. (1000 bbl/day) EF (scm/bbl)

9.46 1683 15.40

8.21 1402 16.05

14.24 2236 17.45

12.86 2460 14.32

6.51 2196 8.13

5.89 2272 7.10

4.96 2044 6.64

4.81 2313 5.70

3.99 2253 4.85

1.50 2831 1.45

1.39 3113 1.22

Year

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

Gas flaring (Bcm) Oil prod. (1000 bbl/day) EF (scm/bbl)

10.99 3358 8.97

11.30 3476 8.90

8.64 3591 6.59

8.89 3672 6.63

11.61 3709 8.58

11.81 3748 8.63

10.99 3728 8.07

10.00 3703 7.39

10.51 3621 7.95

10.51 3765 7.64

7.39 3800 5.33

Year

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Gas flaring (Bcm) Oil prod. (1000 bbl/day) EF (scm/bbl)

8.21 3524 6.38

12.09 3833 8.64

12.20 4104 8.15

12.01 4239 7.76

15.83 4149 10.45

15.69 4039 10.64

16.82 4178 11.03

15.89 4178 10.42

16.59 4243 10.71

16.65 4265 10.70

17.56 3589 13.40

% Gas-flaring-related CO2 emission to total CO2 emission

Bold texts and numbers signify the importance and focal areas relevant to this paper.

sanctions forced NIOC to extract oil from the shared fields which are mainly offshore with fewer plans for collecting the associated gas. As evidence, the gas flaring emission factor for Iranian Offshore Oil Company (IOOC) is the highest among the others (see Table 5). Thus, while the overall oil production has been dropped, the flared gas volume has not been reduced. In addition, there is great amount of uncertainty in gas flaring data reporting.

80% 70% 60% 50% 40% 30% 20%

10.3. Natural gas supply and demand in Iran

10% 0% 1960

1970

1980

1990

2000

2010

2020

4500

18

4000

16

3500

14

3000

12

2500

10

2000

8

1500

6 4

1000 Oil Production

500 0 1970

Gas Flaring

1980

1990

2000

2010

2

Gas Flaring Emission Factor (cm/bbl)

Oil Production (bbl/day)

Fig. 10. Iran’s gas flaring-related CO2 emission share from total CO2 emission based on CDIAC data (CDIAC, 2014).

0 2020

Fig. 11. Iran’s oil production and gas flaring emission factors in the period of 1980–2012 based on EIA data (EIA, 2015).

Table 7 shows Iran’s gas flaring emission factors for the period 1980–2012 based on oil production and gas flaring data for Iran which is also plotted in Fig. 11. From this table and figure it can be seen that the gas flaring emission factor in Iran has had great fluctuations in the 32 years of record: in early 1980s when oil production was disrupted because of the Islamic Revolution in 1979 and the oil production dropped by at least 50%, emission factors were high as much as 17.45 in 1982. As oil production resumed to more than 3 million bbl/day in 1990, emission factor dropped to a very low value of 1.22. Emission factor then remained relatively constant during 1990s at an average of about 7.9 and it remained approximately at that level until 2005. However, since 2006, emission factors show an increasing trend which could be due to disruption of oil production caused by international sanctions in early 2012. The oil production reduction due to the international

This section presents a brief status of natural gas supply and demand in Iran. It helps to understand the linkage between the oil and natural gas production in the overall energy scheme of the country. Since natural gas production does not have significant amounts of gas flaring emissions comparable to oil production emissions, it explains some of the reasons for delays in implementation of the associated gas flaring projects. This information is also useful for the forecast of the gas flaring associated with the oil production. Based on OPEC annual statistical bulletin in 2013 (OPEC, 2013), Iran has the second natural gas proved resources (33.78 Tcm) in the world after Russia (48.68 Tcm) (OPEC, 2013), whereas according to British Petroleum (BP) in its 2013 Review of World Energy (BP, 2013), Iran has the first rank in proven natural gas reserves (33.62 Tcm for Iran and 32.92 Tcm for Russia). According to the World Oil News Center (Tuttle and Salehi, 2013), in 2014 Iran will lead the Gas Exporting Countries Forum (GECF) with 13 member countries holding 60% of the world’s natural gas reserves. US and EU sanctions have cut the Persian nation’s crude exports by half since 2011 and are stiffing projects to export some of its gas, the world’s largest gas reserve. Iran is one of three GECF members that are net importers as the group faces increased competition from LNG projects from the US to Australia. Iran flared 11.4 Bcm of gas in 2011, the last year for which data is available, according to the World Bank’s Gas Flaring Reduction Public–Private Partnership (World Bank, 2014). As will be discussed below in Section 10.5, under the new Gas Flaring Law, the selling price of flare gas is going to be one third of the price of refined natural (nonassociated gas) delivered to industries by the National Iranian Gas Company. On the basis of the energy supply and demand analysis, the environmental damage from air pollution in Iran was assessed. The damage cost to the global environment from the flaring of natural gas, based on the price of $10/ton CO2 was estimated to be 600 million USD per year. This is equal to a little less than 1% of GDP 2002 (Shafie-Pour and Ardestani, 2007). Iran’s gas flaring is about 8% of the global flaring (World Bank, 2014). That would meet about a quarter of demand in South Korea, the world’s second buyer of LNG after Japan. The gas is worth 7.3 billion USD on Southeast Asian

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Table 8 Natural gas supply (a) and demand (b) in NIOC in 2011 based on IIES data (IIES, 2011). (a) Supply Associated gases Gas caps Independent gas fields Sum Associated gases Gas caps Independent gas fields Sum

Onshore regions

Offshore regions

Total associated gases Total gas caps Total independent gas fields Total gas production

78.94 29.93 262.88 371.75 24.92 0 234.45 259.37 103.86 29.93 497.33 631.12

(b) Demand Self-consumption Gas plants and LNG units Gas refineries Petrochemicals Gas condensate and statistical errors Injection Flared gas Total gas consumption

5.97 78.32 469.36 7.19 1.34 31.45 37.46 631.09

Note: All units are in million standard cubic meters per day. Bold texts and numbers signify the importance and focal areas relevant to this paper.

spot markets, according to Bloomberg calculations using World Gas Intelligence prices. Iran flares associated gas because it lacks the infrastructure to process and transport it to market (Tuttle and Salehi, 2013). In Iran natural gas plays a major role in the energy supply basket. Table 8 shows the supply and demand of natural gas in Iran. Associated natural gas production originates mainly from the Khuzestan, Ilam, and Kermanshah provinces, along with offshore oil fields (EIA, 2014). Gross natural gas production totaled almost 631 MMscmd in 2011 most of which was marketed (562 MMscmd), and the remainder was re-injected into oil wells to enhance oil recovery (31.45 MMscmd) and vented and flared (37.46 MMscmd). Re-injecting natural gas plays a critical role in oil recovery at Iran’s fields. As a result, natural gas reinjection is expected to increase in the coming years. Some estimates indicate that NIOC will require around 0.2 billion cubic meters per day of natural gas for reinjection into its oil fields in the next decade, according to FACTS Global Energy (EIA, 2014). Iran also burns off a substantial portion of its gross production which is around 6% in 2011 (IIES, 2011). 10.4. Major gas gathering projects in Iran The most important gas gathering projects in oil production (associated gas) of Iran are listed in Table 9 below. The latest estimates show that around 10 billion USD investment is needed to implement all the planned gas recovery projects (Personal Communication, 2014). Considering the amount of energy saved as a result of implementation of these projects and the environmental cost of air pollution and greenhouse gas emission of flare gases, this amount of investment is not too high and it will have high rate of return. The Iranian Government and the National Iranian Oil Company (NIOC) have a policy objective to reduce gas flaring. NIOC’s gas flaring reduction plans have been listed in Table 9. As it is shown in Fig. 12, gas flaring volume is expected to decrease by implementation of the mentioned projects. A large gap between the actual and planned gas flaring volume can be seen. In order to reduce gas flaring in Iran, the projects had been planned to reach low flaring target in 2012, but the international sanctions

Flared Associated Gas Volume (million cubic meters per day)

M. Soltanieh et al. / International Journal of Greenhouse Gas Control xxx (2016) xxx–xxx

50 45 40 35 30 25 20 15 10 5 0 2004

17

Actual

Planned

2006

2008

2010

2012

2014

2016

Fig. 12. Flared gas volume actual and planned trend. Note: Dashed curve is based on reductions from implementation of flared gas recovery projects during 2011–2015.

delayed their implementation to an unknown date. There are many projects planned or under construction which need large amount of capital investment and new technologies. According to a recent EIA report on Iran (EIA, 2014), the sanctions and lack of international involvement have particularly affected upstream projects, as the lack of expertise, technology, and financial investment has resulted in delays and, in some cases, cancelations of projects. Nonetheless, development of a few projects continues, albeit at a slower pace than planned. These reasons plus other domestic economic reasons have led to major delays in completing the planned projects which could have decreased a large amount of flaring, if they were implemented on time. In the following, some details of these major gas gathering projects will be presented. 10.4.1. AMAK projects The objectives of AMAK (Ab-Teymour, Mansuri, Marun, Ahwaz and Kupal) projects are gathering, compressing, dehydrating and sweetening of the sour associated gases, flared in seven production units and transfer the sweet gas to NGL plants and the acid gas to the Razi Petrochemical Complex. The AMAK project has been implemented since 2010 and comprises of 10 projects and 7 compression stations for gathering and transportation of the associated gases to the production units (Shams Ardekani, 2014). The average emission factor of the seven AMAK projects is around 23.2 cubic meters of gas per barrel of produced oil (6.8 MMscmd sour associated gas versus 292,880 bbl/day produced oil) (AGGP, 2005). This overall emission factor of 23.2 is relatively high compared with the national average of around 7.2 and the global average of around 4.6 (see Table 1 above). As a result of implementation of these projects great environmental benefits is achieved that include: stop flaring and wasting 6.8 million cubic meters of highly sour natural gas, containing 18,400 ppm hydrogen sulfide, which was otherwise flared with extremely high economic value, avoiding emission of 18,000 tons/day of air pollutants, and avoiding consumption of the atmospheric oxygen at the rate of 640,000 m3 /h. In addition, the useful products of the implementation of these projects include: 141 Mscmd lean gas (mostly natural gas), 9450 bbl/day of propane, 6560 bbl/day of butane, 5280 bbl/day of naphta and 180 tons/day of sulfur. The economic values of these projects include: Annual Product Value (APV) of 210 million USD, Net Present Value (NPV) at 6% rate of 687.7 million USD, the IRR of 28% and PBP of 30 months. These indicators are all in favor of immediate action on implementation of these projects with great economic and environmental advantages with an estimated investment cost of 531 million USD (based

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Table 9 Flared gas recovery planned projects in NIOC in Iran, 2011 updates. Gas volume (MCMPD)

Progress Planned

National Iranian South Oil Company Gas recovery and re-injection1 Two-phase pumping for re-injection Gas recovery and re-injection2 Gas recovery and re-injection Re-injection system optimization Gas recovery and re-injection Re-injection system optimization Sour gas recovery for NGL unit feed Gas recovery and re-injection Gas recovery and re-injection Re-injection system optimization Sour gas recovery for NGL unit feed Optimization of NGL feed supply

–

85.76% 2.72% 95.96% 68.47% 66.13% 4.20% 3.85% 2.50% 66.30% 13.20% 4.35% 3.85% 0.00%

Commissioning year Actual 73.31% 2% 95.91% 40.05% 43.46% 2.93% 3.85% 2.50% 66.30% 13.20% 4.26% 3.85% 0.00%

2011 2013 2011 2012 2013 2013 2013 2014 2011 2013 2014 2013 2015

66% 34% 4% 31%

2012 2011 2014 2014 2014 2014 2011 2012 2011 2012

Iranian Central Oil Fields Company Gas Recovery and Injection Compression Station and Injection NGL Gas Recovery and Injection Compression Station

1.64 (From one oil field) 0.52 (from one oil field) 7.19 (from one oil field) 2.92 (from 3 oil fields) 0.28 (from one oil field)

Iranian Offshore Oil Company Kharg NGL3 Siri NGL4 To National Gas Network To National Gas Network To National Gas Network

18.12 (from 7 oil fields) 2.87 (from 4 oil fields) 0.93 (from one oil field) 0.85 (from one oil field) 4.53 (from one oil field)

100% 100% 100% 75% 3%

21% 97% 97% 54% 5%

Arvandan Oil and Gas Company NGL unit Gas Injection

15.25 (from 6 oil fields) 7.93 (from one oil field)

– –

– –

– – – Engineering study –

– –

1

This is the Ghalenar oil fields gas recovery and re- injection that has been completed in 2013, preventing 0.3 MMscmd gas flaring. This is the Nargesi oil fields gas recovery and re-injection that has been completed in 2013, preventing 0.5 MMscmd gas flaring. 3 Kharg project’s physical progress is reported about 44% in 2014. 4 Siri NGL project has been partially implemented. Although the project is almost completed, because of imposed international sanctions causing problems with gas compression unit, in this field around 1.4–1.7 MMscmd gas is flared. 2

on 2005 calculation) which can be returned in less than three years. 10.4.2. Kharg and Behregansar projects Flaring of the associated gas at Kharg Island of Iran in the Persian Gulf and the related offshore fields has been a major source of CO2 emissions for decades. Most of the gas flared is of an acidic nature, which presents a substantial technical and financial barrier to end flaring, despite long-term efforts to alleviate the situation. The CDM project activity in this field was designed to capture and treat associated gas that had been flared at the Soroosh & Nowrooz offshore oil fields and connect this gas to a common trunkline at the Aboozar Gas Compressor Platform. The gas will then be brought to Kharg Island where the gas will be transferred to an existing gas pipeline to serve gas users on the island: primarily oil processing facilities, power generation and a petrochemical facility. The project activity is a sub-component of the Kharg-Bahregansar NGL and Acid Gas Treatment project (Kharg NGL project) designed to capture and utilize all the associated gas in the Kharg Bahregansar area. The project activity encompasses the recovery of the sweet associated gas at the Soroosh and Nowrooz oil production platforms (CDM PDD, 2006). The infrastructure consists of: • • • •

Gas compression and dehydration on the oil field platforms; Subsea gas gathering system and the gas transmission lines; Onshore reception facilities, i.e. separator(s) at Dorood II; Connecting onshore pipeline between the landing site of the offshore pipelines, the reception facilities and the existing gas distribution system on the island.

The Kharg and Behregansar is the largest gas flaring oil field in Iran with an estimated amount of 15.3 MMscmd. Of this amount, 8.4 MMscmd is offshore and 6.9 MMscmd in onshore (AGGP, 2005). The recovered gas will avoid emission of around 5 million tons of CO2 annually. The contribution of each oil field in Kharg and Behregansar region to SOx and NOx emissions are shown in Fig. 13. It should be noted that the calculations behind the figure is based on air dispersion models. It can be seen that most of sulfur compounds are emitted from Dorood Foroozan and Aboozar and Dorood 2 oil fields, which have highly acidic gases. However, most of the NOx emissions are from the Foroozan, Nowrooz and Behregan and onshore facilities. It should be noted that the Kharg Island Gas Gathering and NGL Recovery Project, to which the Soroosh and Nowrooz Early Gas Gathering CDM Project (CDM PDD, 2006) was an original part, despite being a high priority for the Iranian Government and NIOC with many years of planning, has not been fully funded. For this reason its allocated cost is increasing due to inflation so that a recent cost estimate for the aforementioned installations and facilities is around 2500 million USD (Personal Communication, 2014). 10.4.3. SIRI project After Kharg and AMAK projects described above, the third largest source of associated gas is the oil field of Siri with volume of about 3.7 MMscmd as estimated in (AGGP, 2005). Total cost of this project is 458 million USD based on 2011 calculations. The SIRI gas gathering project also has many elements including:

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Fig. 13. The contribution of each oil field in Kharg and Behregansar region to SOx (a) and NOx emissions (b) (AGGP, 2005).

• • • • • •

Offshore gas gathering Onshore gas gathering Acid gas removal and acid gas incineration NGL plant LPG, pentane and condensate storage and loading Residue gas export to Kish and Qeshm Islands.

Note that although the physical progress of Siri project is about 97%, due to the imposed international sanctions this site still flares around 1.4–1.7 MMscmd of the associated gases. This problem is due to the compression unit of the project as mentioned in the footnote of Table 9. 10.5. Gas flaring laws and policies The only law to curb gas flaring in Iran was approved by the Parliament (Majles Shoraye Eslami) in the Annual Budget Law of 2011 and with a slight change in the Annual Budget Law of 2013. According to this law the Ministry of Petroleum was permitted to sell the associated gas currently flared through its affiliated state companies to the private companies at one-third of the selling price of the refined natural gas delivered to industries by the National Iranian Gas Company (NIGC). The Ministry can then spend the income gained from this source for its own environmental projects or those of its affiliated companies. The 2013 version of this Law (Article 15–3 of the 2013 Budget Law) required that the selling should be carried out through a public bid competition. However, it seems that for several reasons such as the lack of economic incentive especially in the long term, this law has not been able to attract and create incentive for companies to invest is gas flaring projects. The following techno-economic constraints maybe the reasons for lack of implementation and unwillingness of private sector to invest in gas flaring projects: • Small volume of certain sources of associated gases; • Remote geographical location; • Variation of pressure and temperature of the gas with time which complicates the engineering design of the project with great uncertainty; • Composition of the gas which makes purification uneconomical; • Cost of purification, transport and injection; • Lack of experience and technology to use the sour gas for small scale generators (Gas-to-Electricity); • Lack of experience and technology to convert the gas to liquid (GTL). In order to facilitate implementation of gas flaring reduction projects, the National Iranian Oil Company (NIOC) plans to prepare

the framework for the public bid competition, which will include the following activities: • The time frame of the completion of the existing projects or the projects at design stage; • The volume and characteristics of the present associated gases and predicted changes in the future; • Priority to be given to those associated gases for which NIOC does not have long-term plans for investment and implementation; • Establish the rules for the full technical, safety and environmental responsibility of the investors in associated gas projects; • Establish the rules for the buy-back of the refined gas, electricity and liquid products (GTL). As noted above, although the Government and NIOC have a policy objective to reduce gas flaring, albeit the objective has not been translated into any specific measures. Unlike many countries, the flaring of gas in Iran does not entail any fees or fines nor does utilization of associated gas provide any fiscal incentives. Further, while NIOC does have plans to implement projects to reduce gas flaring, it is chronically underfunded for capital projects as all profits go directly to the Treasury and the capital budget is approved directly by the National Assembly (Majlis). CAPEX of each project needs the approval of the NIOC Board of Directors. Given that social services require major subsidies, the Government is not able to fund all the capital projects requested by NIOC and since the associated gas capture projects have low rates of return, partly due to the low domestic gas prices, such projects are generally deferred (CDM PDD, 2006). One reason that Iran flares large quantities of the associated gas in oil production, while it has a growing gas demand, is that it has such large quantities of non-associated gas produced from natural gas reserves. Indeed, Iran can meet almost all its domestic needs from the giant South Pars field alone. While the development of gas for international markets will ultimately impact the domestic demand situation, the international export of major amounts of gas from Iran, either by pipeline or LNG is still largely in the planning stage, and is not expected to exert any major pressure on domestic supply in the near to medium term. In fact, Iran’s very abundance of natural gas and its ability to benefit from economies of scale to bring on giant fields like South Pars is an important reason that gas capture projects related to associated gas flaring are continually disadvantaged in the competition for limited capital funds (CDM PDD, 2006). In addition, according to the National Iranian Gas Company (NIGC), it is the policy of this company to implement the “no flare” policy in all natural gas refineries of Iran by the end of the Fifth Five-Year National Development Plan (the end of 2016) (Mehrnews, 2012). This rather easier flare emission reduction opportunity also could compete with gas flaring reduction projects in oil production that causes delay in such projects.

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11. Conclusions Global gas flaring has continued since the inception of oil production more than one and a half century ago. Gas flaring is a great loss of energy resources with significant local, regional and global environment consequences caused by emission of millions of tons of air pollutants and greenhouse gases each year. In addition to gas flaring in oil production, gas flaring is also practiced in other oil, gas and petrochemical industries mostly for operational and safety reasons, the magnitude of gas flaring in those industries is small compared to the gas flaring in oil production. Only about 20 countries account for more than 90% of the global gas flaring. The amount of gas flaring compared to the oil production (emission factor) is highly variable from less than 1 cubic meter per barrel of oil produced to more than 50 cubic meters per barrel of oil. The emission factor also varies with time and location of production. There is significant amount of uncertainty in the estimates of the volume and composition of flare gases that needs to be resolved. Actual measurement of the volume and composition of flare gas is very limited and most data are estimates. It is hoped that the on-going research project on the measurement of the volume and composition of flare gases and various pollutants before and after combustion from the Iranian oil and gas fields can reduce the level of uncertainty in this important environmental problem in the future. Field measurement requires regulatory measures by the national governments, investment by oil companies and international collaboration. The problem with offshore production is even more serious due to the limited space for any capture plants and downstream processing and utilization. Most estimates are based on satellite data and few on actual measurements. This paucity of observations needs the immediate attention of both the oil companies and environmental enforcement bodies and relevant international organizations. There are various methods and technologies available to reduce the gas flaring. However, due to the limited financial resources, lack of policy and regulatory measures and constraints to access the required technologies, in particular by developing countries, gas flaring continues in most parts of the world at a continuous and alarming rate. Various air pollutants and greenhouse gases are emitted from flaring operations, extremely harmful for the local and global environment. This review shows that many good studies on gas flaring have been carried out globally, but effective abatement measures and real actions have been limited. There exists an urgent need for action on this important energy/environment issue. Iran’s gas flaring record shows that for more than a century flaring has had a large fluctuation due to oil production variations. Although Iran does have plans to cut the gas flaring volume, but economical, policy, and technological constraints have delayed the implementation of these projects, which could otherwise provide a large amount of energy with great environmental benefit. The situation has been exacerbated due to international sanctions against Iran, especially the oil sanctions in recent years. The fact that for economic reasons the associated gas is currently flared at many oil production sites, the abundant supply of natural gas and its relatively lower prices, and the lack of strict regulations at national and international levels, are the main reasons for continuing gas flaring practice. However, several successfully implemented projects in Iran such as AMAK since 2010, Siri since 2012, Soroosh and Nowrooz (part of the Kharg Project) since 2010, Ghalenar and Nargesi since 2013 show that it is possible to reduce gas flaring emissions provided that financial resources, national policies and regulations and technological constraints are lifted. Iran’s gas flaring can be reduced significantly as planned provided that the financial and technological constraints due to international sanctions are removed.

The final message from this review paper may be adopted from a recent report prepared by the Norwegian University of Science and Technology (Andersen et al., 2012). The technology to address the problem of gas flaring exists today and the policy regulations required are largely understood. A lot of research has been conducted on the topic, but still each year an amount of around 150 billion cubic meters of natural gas is flared around the world, contaminating the environment with 400 million tons of CO2 annually. Having the necessary technology and knowing the cradle of the problem, what stands in our way to take this huge and yet seemingly easy step to reduce emissions? It seems like the global community did not do its homework when the solution to such a renowned problem is so obvious, but is it really the case (Andersen et al., 2012)? Acknowledgment This work was initiated and carried out while the first author was on sabbatical in the Department of Atmospheric and Oceanic Science of the University of Maryland, USA. The corresponding author is grateful to the University of Maryland, in particular Dr. Eugenia Kalnay for her financial support and to Dr. J. Carton, the Chair of the department for hosting his sabbatical, and to Dr. Russ Dickerson for the useful discussions and in particular for taking his time to review this paper with several critical and constructive comments. Many individuals including my former graduate students, several friends and experts in NIOC, National Iranian Oil Company; NIGC, National Iranian Gas Company; NIPC, National Iranian Petrochemical Company; Mehr Renewable Energy Company, etc. have provided valuable information for preparation of this review. The financial support provided by Sharif University of Technology and the University of Maryland for the first author’s sabbatical is highly appreciated. Appendix A. Flare gas sampling, combustion efficiency, emission factor and composition Flare sampling: To the authors’ knowledge there is no standard method for flare gas sampling. The sampling methodology explained here refers to the experiments of McDaniel’s study (1983). In that methodology, the sampling is employed by the means of a specially constructed probe suspended by a crane over the flare flame. The sample extracted by the probe is monitored continuously to determine concentrations of carbon dioxide (CO2 ), carbon monoxide (CO), total hydrocarbons (THC), sulfur dioxide (SO2 ), oxides of nitrogen (NOx ) and oxygen (O2 ). In addition, the probe tip temperature, ambient air temperature and wind speed and direction are measured. Integrated samples of the flare plume are collected for hydrocarbon species analysis by gas chromatograph. Particulate matter samples are collected during the smoking flare tests. Combustion efficiency: It defines the percentage of flare emissions that are completely oxidized to CO2 . Mathematically the combustion efficiency (CE) is defined as: %CE =

CO2 CO2 + CO + TCH + Soot

where CO2 , CO and Soot are in parts per million by volume; THC is in parts per million by volume of total hydrocarbon as methane. In general, when flares are operated under conditions representative of industrial practices, the combustion efficiencies in the flare plume are greater than 98% (EPA, 1991), that was also observed in McDaniel’s study. In addition, the concentrations of NOx emissions in the flare plume were observed to be in the range of 0.5–8.16 ppm

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(McDaniel, 1983). In McDaniel’s study (1983), it is assumed that accuracy of the combustion efficiency calculations is dependent on two primary sources of error: (l) the accuracy of the listed concentrations of the calibration gases, and (2) the accuracy of the instruments’ measurements of the gaseous samples (instrument drift, interference, repeatability, etc.). Other systemic errors due to sampling, data acquisition, etc. are assumed to be negligible. Therefore, the total worse case accuracy error for CO, CO2 , THC, NOx , O2 and SO2 is reported as ±9.7 ppm, ±2545 ppm, ±2.3 ppm, ±1.0 ppm, ±0.69%, and ±0.065 ppm, respectively. A semi-empirical relationship has been suggested by Kostiuk and his co-workers to estimate the efficiency of a flare burning in a crosswind (Kostiuk et al., 2004):



3

(1 − )(LHVmass ) = A · exp

B



U∞ (gVj d0 )

1/3

where LHVmass is the lower heating value of the flare stream on a mass basis and g is the gravitational acceleration. The coefficients, A and B, are the following: A = 133.3 (MJ/kg)3 and B = 0.317 for methane base flares; and A = 32.06 (MJ/kg)3 and B = 0.272 for propane and ethane based flares. For natural gas-based flare streams, at energy densities below 15 MJ/m3 significant inefficiencies result at wind speeds as low as 1 m/s. Therefore, based on this model and current data, the recommendation is made to raise the lowest permissible energy density of flare streams to 20 MJ/m3 . For a flare burning pure methane with a measured efficiency of 97.18%, the calculated uncertainty is ±0.6% absolute. For the same flare under different wind conditions and with a measured efficiency of 91.79%, the calculated uncertainty is ±0.15% absolute (Kostiuk et al., 2004). While these statistical uncertainties are small, it is notable that these values only reflect the uncertainties of the terms present in the aforementioned equation. The authors have mentioned that assumptions used in the development of the methodology must be tested by other means (Kostiuk et al., 2004). Gas flaring emission factor: When a gas flaring project is being planned (e.g. a project to be submitted as the Clean Development Mechanism – CDM), only the CO2 emission as the main greenhouse gas, is considered. Therefore, in calculating baseline emissions, it is assumed that the recovered gas would be flared in the absence of the project. It is also assumed that all carbon in the tail gas (i.e. in methane and other gases including other hydrocarbons, CO, and CO2 ) is completely oxidized to carbon dioxide. From the environmental point of view, emission of CO, SO2 , NOx , and BC even small is important. Many investigations and reference guidelines are devoted to estimate these emissions. IPCC has developed a three Tier-based emission inventory. This procedure for vent and flare related emission has been described in Chapter 4: Fugitive Emissions of 2006 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC, 2006). Emission factor values are accessible in IPCC emission factor database (EFDB), manufacturer’s data or other appropriate sources. It is recommended to compare the IPCC default factors to national or local data to provide further indication that the factors are applicable. Emission factor uncertainties are less than or equal to ±100 percent, a normal distribution has been assumed, resulting in a symmetric distribution about the mean. Default emission factors for flaring in oil and gas extraction is also given in European Environmental Agency (EEA) EMEP emission inventory guidebook 2013 (EEA, 2013). The default emission factors in this guidebook are reported for NOx , CO and non-methane VOCs along with upper and lower limits of emission factor with 95% confidence interval. For a set of pilot scale flare experiments performed in Iran, the range of observed averaged emission factors (including different flared gases compositions) were 0.10–0.59 kg/109 J, 49.0–51.6 kg/109 J, and 0.020–0.035 kg/109 J for CO, CO2 , and NOx ,

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respectively (Talebi et al., 2014). It should be noted here that the National Iranian Oil Company (NIOC), being aware of the uncertainties in the gas flaring operations and emissions, has planned to attain local emission factors for its upstream oil facilities including gas flares. The project is on-going and the results have not been published yet. Sample composition: Sample associated gas composition and characteristics flared in Soroosh & Nowrooz oil fields in Persian Gulf (CDM PDD, 2006): Composition (mole %)

Nowrooz

Soroosh

Carbon dioxide Methane Ethane Propane Butane Pentanes Hexanes Nitrogen Water H2 S Total gas Net calorific value (MJ/Nm3 ): Carbon intensity fuel (kg C/MJ): Carbon content (kg C/Nm3 ) Mass fraction of methane (kg CH4 /kg): Carbon content (kg C/kg): Gas density (kg/Nm3 ):

0.93 75.83 13.12 6.99 2.17 0.74 0.13 0.09 0.00 0.00 100.00 48.1 0.0146 0.7021 55.51% 76.51% 0.92

1.52 40.75 21.54 23.83 10.20 1.28 0.05 0.84 0.00 0.00 100.01 66.2 0.0156 1.0344 20.97% 78.32% 1.32

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Please cite this article in press as: Soltanieh, M., et al., A review of global gas flaring and venting and impact on the environment: Case study of Iran. Int. J. Greenhouse Gas Control (2016), http://dx.doi.org/10.1016/j.ijggc.2016.02.010