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Environmental


DIRECT GREENHOUSE GAS EMISSIONS

Million tonnes CO2 equivalent
Greenhouse gas emissions (line chart)

Greenhouse gas emissions

The direct greenhouse gas (GHG) emissions from facilities we operate were 74 million tonnes on a CO2-equivalent basis in 2011, a decrease of around 3% from 2010. The main reasons for this slight drop were divestments in our Downstream business and reduced flaring in Nigeria. These were partly offset by the start of production at the Pearl GTL plant in Qatar and the Athabasca Oil Sands Project expansion in Canada.

Around 55% of our GHG emissions came from the refineries and chemical plants in our Downstream business. The production of oil and gas in our Upstream business accounted for around 40% of our GHG emissions, and our shipping activities for the remaining 5%. We continue to work on improving operational performance and energy efficiency to reduce GHG emissions.

The indirect GHG emissions from the energy we purchased (electricity, heat and steam) were 10 million tonnes on a CO2-equivalent basis in 2011, the same as in 2010. We estimate that the CO2 emissions from the use of our products were around 570 million tonnes in 2011.


FLARING – UPSTREAM
Million tonnes CO2 equivalent
Flaring – upstream (line chart)

Flaring

In 2011, the flaring of natural gas in our Upstream business decreased by around 4% compared to 2010, to 10.0 million tonnes of CO2 equivalent. We made progress in reducing flaring in Nigeria in 2011. Although onshore oil production in Nigeria rose by around 4%, flaring emissions were down almost 20%, to 6.1 million tonnes of CO2 equivalent. This was because more gas-gathering equipment was brought on-stream and more controls were applied to sites with higher levels of gas associated with oil production. The decrease in Nigeria was partly offset by increased flaring during the start-up of production at the Pearl GTL plant in Qatar. Overall, flaring made up around 15% of the total direct GHG emissions in 2011.

Operational flaring for safety reasons, or during the start-up of Upstream facilities, accounted for around 35% of flaring emissions. We aim to minimise this operational flaring.

Continuous flaring, due to a lack of equipment to capture the gas produced with oil, accounted for the remaining 65% of flaring emissions. Around 80% of this continuous flaring took place in Nigeria, where the security situation and lack of government funding has previously slowed progress on projects to capture the gas. Around 15% of the continuous flaring came from the Majnoon field in Iraq where we are now the operator. We expect that flaring in Iraq will rise in future years as production increases and before equipment to gather the associated gas can be installed. When we acquire or become the operator of an existing facility that is already flaring or venting (releasing gas to the atmosphere), it takes time before these activities can be stopped.

Outside Nigeria and Iraq, the few facilities that continuously flare accounted for less than 1% of our total direct GHG emissions in 2011. Some of these facilities are at ageing oil fields where the associated gas pressure is too low to power the compressors used to gather the gas and avoid flaring.

Our HSSE & SP Control Framework requires our new facilities to be designed so as not to flare or vent continuously.


ENERGY INTENSITY – UPSTREAM
(EXCL. OIL SANDS AND GTL)
Gigajoules/tonne production
Energy intensity – upstream (line chart)

Energy efficiency

One of the ways we can manage our direct GHG emissions is to improve the energy efficiency of the facilities we operate.

In 2011, the overall energy efficiency for the production of oil and gas in our Upstream business worsened slightly compared to 2010, but was around the same level as in earlier years. All our major facilities have energy management plans in place that include making the best use of those facilities and using improved techniques in field management. We expect that maintaining the energy efficiency levels of recent years will be difficult in the future as existing fields age and production comes from more energy-intensive sources.

In our oil sands operations, energy intensity in 2011 worsened slightly compared to 2010, as efforts to improve the energy efficiency of our operations were offset by the start of production at the Jackpine Mine and Scotford Upgrader expansion.

ENERGY INTENSITY – OIL SANDS
Gigajoules/tonne production [A]
Energy intensity – oil sands (line chart)

[A] Includes mining and upgrading operations

In 2011, the overall energy efficiency for the manufacture of oil products at our refineries improved compared to 2010, helped by continued progress with our CO2 and energy management programme and increased use of refinery capacity. Although improved over the past two years, the energy intensity of our refineries remained high compared to earlier years as a result of continued reduced demand for oil products. Reduced output leads to higher energy intensity as the energy needed to run refineries does not decrease significantly at lower production levels.

The overall energy efficiency of our chemical plants worsened in 2011, compared to 2010. Our chemical plants experienced unplanned maintenance and lower demand for products, leading to the plants running at reduced output.

Our refineries and chemical plants continue to implement the CO2 and energy management programme to improve their energy efficiency performance.

ENERGY INTENSITY – REFINERIES
Refinery Energy Index [B]
Energy intensity – refineries (line chart)

[B] Indexed to 2002; based on 2006 Solomon EIITM methodology
ENERGY INTENSITY – CHEMICAL PLANTS
Chemicals Energy Index
Energy intensity – chemical plants (line chart)


SPILLS – OPERATIONAL AND SABOTAGE [C]
Number of spills
Spills – Operational and Sabotage; Number of spills: (line chart)

[C] Over 100 kilograms

Spills

Shell has clear requirements and procedures to prevent operational spills, and multi-billion dollar programmes in place to maintain and improve our facilities and pipelines. However, spills still occur for reasons such as operational failure, accidents or corrosion.

In 2011, our operational spills of oil and oil products totalled 6.0 thousand tonnes, up from 2.9 thousand tonnes in 2010. Around 80% of the volume in 2011 was from a single spill of 4.8 thousand tonnes at the Bonga field off the coast of Nigeria. We continue to investigate and learn from all spills to improve our performance.

SPILLS – OPERATIONAL AND SABOTAGE [D]
Volume in thousand tonnes
Spills – Operational and Sabotage; Volume in thousand tonnes: (line chart)

[D] Over 100 kilograms

The number of operational spills increased slightly to 208 in 2011, from 195 in 2010, as equipment in Nigeria was put back into service. We are working to extend the significant improvements made in previous years in the number of operational spills through our continued investment in improving the reliability and maintenance of our facilities.

In 2011, sabotage and theft in Nigeria remained a significant cause of spills, totalling 1.6 thousand tonnes. This was a decrease in volume from 2010 and is the lowest level recorded since 2005. However, the number of these spills increased slightly to 118 in 2011, from 112 the previous year.

As of the end of March 2012, there were two spills under investigation in Nigeria that may result in adjustments to the 2011 data. See Nigeria for more information on spills in Nigeria.


FRESH WATER WITHDRAWN

Million cubic metres
Fresh water withdrawn (line chart)

Water

The way we manage our use of fresh water is especially important in areas of the world that are water constrained due to limited supplies or extensive use. We assess the availability of water where we operate, and design and run our facilities in ways that help reduce their water use.

In 2011, our use of fresh water increased to 209 million cubic metres, from 202 million cubic metres in 2010. This was primarily due to increased water consumption following the start of production at the Athabasca Oil Sands Project expansion in Canada. Our Downstream business accounted for around 75% of our fresh-water use for the manufacture of oil products and chemicals; our Upstream operations used around 25%. In water-scarce areas, we have water management plans that outline how our operations will reduce, recycle and monitor water use.