OGP DATA SERIES - اصلی

ENVIRONMENTAL PERFORMANCE INDICATORS – 2012 DATAReport No. 2012e (November 2013)

OGP DATA SERIES

I n t e r n a t i o n a l A s s o c i a t i o n o f O i l & G a s P r o d u c e r s

P ublications

Global experience

The International Association of Oil & Gas Producers has access to a wealth of technical knowledge and experience with its members operating around the world in many different terrains. We collate and distil this valuable knowledge for the industry to use as guidelines for good practice by individual members.

Consistent high quality database and guidelines

Our overall aim is to ensure a consistent approach to training, management and best practice throughout the world.

The oil & gas exploration & production industry recognises the need to develop consistent databases and records in certain fields. The OGP’s members are encouraged to use the guidelines as a starting point for their operations or to supplement their own policies and regulations which may apply locally.

Internationally recognised source of industry information

Many of our guidelines have been recognised and used by international authorities and safety and environmental bodies. Requests come from governments and non-government organisations around the world as well as from non-member companies.

Disclaimer

Whilst every effort has been made to ensure the accuracy of the information contained in this publication, neither the OGP nor any of its members past present or future warrants its accuracy or will, regardless of its or their negligence, assume liability for any foreseeable or unforeseeable use made thereof, which liability is hereby excluded. Consequently, such use is at the recipient’s own risk on the basis that any use by the recipient constitutes agreement to the terms of this disclaimer. The recipient is obliged to inform any subsequent recipient of such terms.

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Environmental performance indicators 2012 data

Report No: 2012e

November 2013

The environmental statistics for 2012 were derived from data provided by the following companies:

Contributing companiesAddax Petroleum LimitedADNOCBGBHP BillitonBPCairn EnergyChevronCNOOCConocoPhillipsDolphin EnergyDONG E&PE.ONEni E&P DivisionExxonMobilGDF SUEZ E&P InternationalHess CorporationHuskyINPEXKosmosKuwait Oil CompanyMaersk OilMarathon Oil CompanyMOLNexenOil SearchOMVPan American EnergyPerencoPetrobrasPetronasPremier OilPTT EPQatar PetroleumRepsol RWESasolShell CompaniesStatoilSuncorTalisman EnergyTotalTullowWintershall

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Environmental performance indicators – 2012 data

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Table of contents

Executive summary iiGaseous emissions ....................................................................................................................................iiEnergy consumption.................................................................................................................................iiFlaring .....................................................................................................................................................iiiAqueous discharges ..................................................................................................................................iiiNon-aqueous drilling fluids retained on cuttings discharged to sea .........................................................iiiSpills .....................................................................................................................................................iii

Introduction 1

Scope of data submissions 2

1 – Gaseous emissions 61.1 Carbon Dioxide (CO2) .......................................................................................................................81.2 Methane (CH4) ..................................................................................................................................91.3 Greenhouse Gas (GHG) ..................................................................................................................101.4 Non-Methane Volatile Organic Compounds (NMVOCs) ............................................................... 111.5 Sulphur dioxide (SO2) ......................................................................................................................121.6 Nitrogen oxides (NOX) ....................................................................................................................13

2 – Energy consumption 14

3 – Flaring 16

4 – Produced Water 174.1 Quality (oil content) of produced water discharges...........................................................................184.2 Quantity of oil discharged in produced water per unit of production ............................................... 194.3 Produced Water Injection ................................................................................................................21

5 – Non-Aqueous Drilling Fluids retained on cuttings discharged to sea 235.1 Non-Aqueous Base Fluid retained on cuttings discharged to sea ......................................................23

6 – Spills 256.1 Oil Spills ..........................................................................................................................................25

Appendix A – Data tables 31Scope of data submissions .......................................................................................................................311. Gaseous emissions ............................................................................................................................332. Energy Consumption .......................................................................................................................363. Flaring .............................................................................................................................................374. Produced Water ...............................................................................................................................385. Non-Aqueous Drilling Fluids retained on cuttings discharged to sea ...............................................446. Spills ................................................................................................................................................45

Appendix B – Glossary 53

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International Association of Oil & Gas Producers

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Over the past 14 years the International Association of Oil & Gas Producers (OGP) has collected environmental data from its member companies on an annual basis. The objective of this programme has been to allow member companies to compare their performance with other companies in the sector leading, it is hoped, to improved and more efficient performance. The programme also contributes to the industry’s wish to be more transparent about its operations.This report summarises information on exploration and production (E&P) activities carried out by contributing OGP member companies in 2012. Data have been submitted for the report by 43 of OGP’s 62 member operating companies working in 78 countries worldwide. This total includes 3 companies reporting for the first time this year and 40 of the 41 companies that contributed data in 2011. Information is aggregated at both global and regional levels and is expressed within 6 environmental indicator categories:

• Gaseous emissions;• Energy consumption;• Flaring;• Aqueous discharges;• Non-aqueous drilling fluids retained on cuttings discharged to sea; and• Spills of oil and chemicals.

These data represent oil and gas wellhead production of 2 232 645 thousand tonnes (in the region of 16.6 billion BOE), about 32% of 2012 global production sales†. This is a 1% increase in the production represented in this report compared with 2011. However, regional coverage is uneven, ranging from almost all known production in Europe to 8% in the Former Soviet Union (FSU).

Gaseous emissions

Releases of gases to the atmosphere are an integral and inevitable part of exploration, production and processing operations. In 2012 participating OGP member companies reported emissions of:

• 253 million tonnes of carbon dioxide (CO2)—equivalent to 132 tonnes of carbon dioxide per thousand tonnes of hydrocarbon production;

• 2.3 million tonnes of methane (CH4)—equivalent to 1.3 tonnes of methane per thousand tonnes of hydrocarbon production;

• 817 thousand tonnes of non-methane volatile organic compounds (NMVOC)—equivalent to 0.5 tonne of NMVOC per thousand tonnes of hydrocarbon production;

• 303 thousand tonnes of sulphur dioxide (SO2)—equivalent to 0.2 tonne of SO2 per thousand tonnes of hydrocarbon production; and

• 796 thousand tonnes of nitrogen oxides (NOX)—equivalent to 0.4 tonne of NOX per thousand tonnes of hydrocarbon production.

Normalised CH4 emissions increased in 2012 by 6% compared with 2011. Normalised NOX emissions increased in 2012 by 5% compared with 2011.Normalised NMVOC emissions decreased in 2012 by 4% compared with 2011.Normalised CO2 emissions and normalised SO2 remained virtually unchanged compared with 2011.

Energy consumption

Production of oil and gas requires significant quantities of energy for extraction, processing and transport. In many oilfields those energy needs are met by locally produced gas.

In 2012, OGP reporting companies consumed on average 1.4 GigaJoules of energy for every tonne of hydrocarbon produced; a 9% reduction compared with the 2011 average. As in previous years, data indicate that onshore production in 2012 was more energy intensive than offshore production.

Executive summary

† Source: BP Energy Review 2013

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Flaring

Flaring is the controlled burning of hydrocarbons produced in the course of petroleum exploration and production operations. It includes the controlled and safe burning of gas that, for commercial, safety or technical reasons, is not used or exported.

In 2012, 13.9 tonnes of gas was flared for every thousand tonnes of hydrocarbon produced versus 15.7 tonnes in 2011 and 16.0 in 2010. Reductions in flaring rates are predominantly driven by major infrastructure improvement projects that increase the capability to inject gas for reservoir maintenance and to deliver gas to markets.

Aqueous discharges

Produced water is the most significant water discharge associated with E&P Operations. For every tonne of hydrocarbon produced in 2012 (including oil, condensates and gas), 0.5 tonne of produced water was discharged and 0.9 tonne of produced water was re-injected.

The quality of produced water discharges is measured in terms of oil content. In 2012, the average concentration of oil in produced water was 6.8 mg/l for onshore discharges and 14.1 mg/l for offshore discharges. When expressed in terms of oil production, overall, these discharges are equivalent to 7.0 tonnes of oil for every million tonnes of hydrocarbon produced.

Comparison with 2011 data indicates that the average concentration of oil in produced water discharged increased in 2012 by 14%. The average quantity of oil discharged per unit of hydrocarbon production increased by 10%. These variations reflect a change in the companies reporting data for oil and produced water discharges.

Non-aqueous drilling fluids retained on cuttings discharged to sea

While much of the offshore drilling is achieved using water-based drilling fluids, some technical requirements during well drilling operations favour the properties that are only available from non-aqueous drilling fluids (NADFs)† . In 2012 reporting companies discharged 20 523 tonnes of non-aqueous base fluids (NABF) on drill cuttings to sea. Of these discharges, 89% contained Group III base fluids and 4% contained Group II fluids, the reporting Group was not given for the remaining 7%. There have been no reports of discharges of Group I fluids retained on cuttings since the reporting of NABF by Group I, II and III classification began in 2003.

Spills

For the purpose of this report a spill is defined as any loss of containment that reaches the environment,in other words, is not retained within secondary or other containment, irrespective of the quantity recovered.

In 2012, participating OGP member companies reported 1 680 oil spills greater than 1 barrel in size, resulting in a normalised spill rate of 0.8 oil spills per million tonnes of hydrocarbon production (1.5 in 2011).

The reported oil spills >1 barrel resulted in the release of a total of 9 483 tonnes of oil. The quantity of oil spilled per unit of hydrocarbon production has fallen to 4.8 tonnes per million tonnes production, 40% lower than the rate for 2011 and 6% higher than the rate for 2010‡.

† Definitions of Group I, II and III base fluids are provided in section 5.1 ‡ This does not include any data related to the Deepwater Horizon incident, which is the subject of on-going, Multi-District litigation.

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Over the past 14 years, OGP has collected environmental information from its member companies on an annual basis. The ultimate aim of this effort is to provide a representative statement on the environmental performance of the contributing OGP member companies. Subsidiary objectives are to provide a basis for individual member companies to compare their environmental performance, thereby helping them to identify areas for improvement and to demonstrate the industry’s wish for greater transparency concerning its activities.

Environmental information relating to emissions and discharges is collected under the following six categories:

• Gaseous emissions;• Energy consumption;• Flaring;• Aqueous discharges;• Non-aqueous drilling fluids retained on cuttings discharged to sea; and• Spills of oil and chemicals.

Data are collected annually for each of the categories above, on the basis of a set of definitions agreed by the OGP membership. These definitions align with the IPIECA/API/OGP Oil and gas industry guidance on voluntary sustainability reporting, OGP report number 437. The definitions are provided via a users’ guide that is reviewed at regular intervals and updated to reflect improvements in reporting and to provide additional clarification.

Annual reports of activities in the years 2003 to 2011 and summary reports for activities in 2001 and 2002 have previously been published and are available from the OGP website at http://www.ogp.org.uk/publications.

Introduction

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Scope of data submissions

Forty three OGP member companies reported environmental information for, on average, six countries each. Data from 78 countries are represented in the report. The data represent 2 233 million tonnes of hydrocarbon production, approximately equivalent to 32% of 2012 world production as reported in the BP Statistical Review 2013.

To view the data from a geographical perspective, 7 regions have been defined.

Figure 0-1: 2012 regional coverage

Figure 0-2: Percentage of known production in this database

Middle East19%

Asia/Australasia 14%

North America 14%

Africa 23%

Europe 17%

FSU 5%South & Central America 8%

Note: The country of Georgia is now reported as part of the FSU region (previously Europe). In this report the change affects gross atmospheric emissions and energy for the two regions for the year 2011 only. Reported production for Georgia was two thousand tonnes or less for the years 2001–2004 and 2006, and 119 thousand tonnes in 2007. Some normalised results published in previous reports are slightly affected for the regions of FSU and Europe:

• CO2, NMVOC and NOX emissions per unit of production for the two regions for the years 2002, 2003, 2006 and 2007.

• Spills per unit of production onshore for the years 2006 and 2007.

• Energy per unit of production, specifically onsite combustion, for 2001–2007 excluding 2005.

• Hydrocarbon flared per unit of production 2007 only.

20%32

16

14 22 15

23

9

28

35%

3378%

70

85 96%

24 23%

71 39%

8%

11North America Europe

Africa

Former Soviet Union

Asia/AustralasiaMiddle EastSouth & Central America

In this context a data set is a set of data with distinct company, country and location (onshore/offshore) where there is both hydrocarbon production data and a positive return (zero or greater) of either atmospheric emissions, aqueous discharges, energy consumption, hydrocarbon flared or spills.

Number of companies providing data

% of known production (as reported in BP Statistical Review)Note: Production figures given in this report relate to ‘gross production’ whereas world data extracted from the BP Statistical Review represent ‘net production’. Thus the data are not direct-ly comparable, but the ‘percentage of world production’ figures are given as indicative of the relative regional contributions in the database. %

n

nCountry represented/Not represented

N.B. Regional allocations for some countries differ from those used in the OGP Articles of Association.

Figure 0-3: Percentage of total data sets in this databaseFSU 3%

Asia/Australasia 22%

North America 10%

South & Central America 10%

Middle East 7%

Europe 26%

Africa 21%

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Fig 0-4: Production associated with OGP database and 2012 production in BP Statistical Review of World Energy—by regionPercentage of known production†

0

20

40

60

80

100

South & Central America

North America

Middle East

FSUEuropeAsia/Australasia

Africa

96

78

111

3935

23 20

8

† Production figures in this report represent wellhead production, which includes oil and gas volumes consumed in operations. The BP Statistical Review provides data on production exported for sale..

This report only reflects the performance of the OGP member companies that have provided data. However where the degree of coverage is highest—for example in Europe where a high percentage of hydrocarbon production is represented - the information can be taken to approximate ‘industry’ performance. In Africa, Asia/Australasia and South & Central America, the data give a broad indication of industry performance. For the Middle East and North America, the regional coverage is less comprehensive, giving a weaker indication of industry performance. For the Former Soviet Union (FSU), data reported by participating companies represent just 8% of the total sales production for that region and thus may not be representative of the region’s performance.

The number of companies reporting has fluctuated between years. Data are presented on a normalised basis to help control for this effect. Nevertheless, normalised performance indicator results may be influenced by changes in the list of reporting companies as well as changes in mixtures of assets held by the participating companies between years. Differences between years for participating companies may also, in some cases, reflect changes in calculation methodology applied or reporting definitions. Thus, though the coverage of E&P activities is good, changes in results may not necessarily reflect actual changes in performance.

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Normalised analyses are only possible when data are available for both the metric to be normalised (emissions, discharges, spills) and the normaliser (hydrocarbon production, produced water). Some of the analyses will cover less than 100% of the total production reported because some companies did not submit data for all metrics covered in the survey. This is particularly relevant to the South & Central American region where around 40% of the submitted data are included in the normalised emissions, energy consumption, flaring and oil discharges results, and to the Middle East region where around 55% of emissions and oil discharges are included in the normalised results. Coverage for the analyses is presented below.

Table 0-1: Percentage of reported production included in normalised analyses†

AfricaAsia/

Australasia Europe FSUMiddle

EastNorth

America


All regions

Gas emissions:

CO2

CH4

NMVOC

SO2

NOX

Energy consumed

Flaring

Oil discharged in produced water

Oil spills

† Green (90%-100%): data fairly representative of region; Yellow (65%-89%): data moderately representative; Orange (30%-64%): data poorly representative; Red (0%-30%): data not representative of region

Table 0-2: Production associated with OGP database and 2012 production in BP Statistical Review of World Energy—by region

AfricaAsia/


EastNorth

America


All regions

Percent of production for which data are reported, by region

78% 39% 96% 8% 23% 20% 35% 32%

In 2009, data on the source types of gaseous emissions (energy, flare, vent, fugitive emissions and other) were collected for the first time. It was recognised that not all participating companies would be able to contribute data at that level of detail in the beginning; nevertheless, data broken down by source cover roughly half of the gaseous emissions reported for 2009, 2010, 2011 and 2012. It is expected that this information will be helpful in understanding some of the trends in the data as well as to help indicate areas for improvement. Data coverage for the breakdown is expected to improve over time.

The current year data shown in this report are based on the best available information that member companies are able to provide at time of publication. In some cases reporting companies have provided corrections to previous years’ data, and the changes have been included in this report where they affect previously published regional or global results. The results affected are listed in Appendix A.

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Detailed Review

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Releases of gases to the atmosphere are an integral and inevitable part of exploration, production and processing operations. The principal (routine) sources are flaring, venting, turbine and engine operation, fluids processing and fugitive losses (for example, from pumps, gas driven valves, flanges and pipes). Non-routine and emergency emissions can arise from well testing, process safety events and emergency flaring and gas venting.

Gaseous emissions covered in this report are those considered most relevant from process control as well as regulatory perspectives. They are:

• CO2: carbon dioxide released to the atmosphere from any source. Carbon monoxide (CO) is not included.

• CH4: methane released to the atmosphere, from any source, including fugitive losses.• Green house gas is CO2 + CH4 expressed as CO2 equivalent.• NMVOCs: Non-Methane Volatile Organic Compounds are all hydrocarbons, other than methane,

released to the atmosphere.• SO2: sulphur dioxide.• NOX: the sum of nitric oxide (NO) and nitrogen dioxide (NO2) expressed as NO2 equivalent. Nitrous

oxide (N2O) is not included as a component of NOX.

Given the wide range of sources of gaseous emissions, it is not practicable (or possible) to measure every single release individually. Industry has, however, developed and updated detailed guidance methodologies to calculate and estimate emissions and losses†. Since companies may use a variety of estimation techniques care must be taken when interpreting aggregated data.

A number of factors affect the quantity of gases emitted from E&P petroleum industry operations. Consequently, understanding the variations in performance in terms of normalised emission ratios is complex. These factors include:

• Presence or absence of infrastructure for gas sales• Gas-oil ratio• Reservoir and field characteristics• Use of hydrocarbon recovery techniques• Regulatory and contractual aspects• Location and logistics• Age of the fields

Emissions from the generation of purchased energy (electricity, steam) are not reported.

Normalised figures for 2012 emissions (see Figure 1-1) are broadly consistent with data published for activities in 2006–2011:

• 132 tonnes of carbon dioxide (CO2) per thousand tonnes of hydrocarbon production;• 1.3 tonnes of methane (CH4) per thousand tonnes of hydrocarbon production;• 0.5 tonne of non-methane volatile organic compounds (NMVOC) per thousand tonnes of hydrocarbon

production;• 0.2 tonne of sulphur dioxide (SO2) per thousand tonnes of hydrocarbon production; and • 0.4 tonne of nitrogen oxides (NOX) per thousand tonnes of hydrocarbon production.

1 – Gaseous emissions

† See for example: Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions (2003) Joint IPIECA/API/OGP report (in revision); SangeaTM Energy and Emissions Estimating System, API, http://ghg.api.org;

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In 2012, participating OGP member companies reported emissions of:• 253 million tonnes of CO2;• 2.3 million tonnes of CH4;• 817 thousand tonnes of NMVOC;• 303 thousand tonnes of SO2; and • 796 thousand tonnes of NOX

Figure 1-1: Emissions per thousand tonnes hydrocarbon productiontonnes per thousand tonnes

0.0

0.5

1.0

1.5

NOXSO2NMVOCCH4

1.33

0.48

0.17

0.43

2012201120102009200820072006

Figure 1-2: CO2 and CH4 expressed as CO2 equivalent per thousand tonnes hydrocarbon productiontonnes per thousand tonnes

0

50

100

150

200

2012201120102009200820072006

132

28

CH4 expressed as CO2 equivalent (CH4 x 21)CO2

Note: As nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride contribute only a small fraction of greenhouse gas emissions from E&P activities, they have not been included here.

The following sub-sections present the overall emission data for the years 2006 to 2012, regional emission data for 2008 to 2012 and atmospheric emissions categorised by the source of the gas release for the years 2011 and 2012. The reporting options for the allocation of source categories are Energy, Flare, Vents, Fugitive losses and Other/unspecified (see Glossary at Appendix B).

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1.1 Carbon Dioxide (CO2)

Emissions of carbon dioxide occur principally from the flaring and combustion of fuels for energy production and are therefore a function of the type and quantity of fuel burned. Carbon dioxide releases may also occur where CO2 is used for enhanced petroleum recovery or where it is stripped from the natural reservoir gases to meet sales specifications.

1.1.1 Emissions per unit of productionGlobal CO2 emissions normalised to hydrocarbon production for 2012 were 132 tonnes of CO2 per thousand tonnes of production, virtually unchanged compared with 2011, as shown in Figure 1.1.1.1.

Regional averages for the quantity of carbon dioxide emissions per unit of production vary from 58 to 214 tonnes of carbon dioxide per thousand tonnes of hydrocarbon production, as shown in Figure 1.1.1.2. In 2011 the range was between 48 and 206 tonnes per thousand tonnes of production.

1.1.2 Emissions by sourceThe source was specified for 59% of the carbon dioxide emissions reported for 2012.

As shown in Figure 1.1.2.1, 61% of the reported carbon dioxide emissions where the source was specified were from energy use, 33% were from flaring and 6% were from venting.

0

20

40

60

80

100

120

140

160142 142 142

135 133 132 132

2006 2007 2008 2009 2010 2011 2012

Figure 1.1.1.1: CO2 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

Vents 6%

Fugitive losses 0.02%

Flare 33%

Energy 61%

Figure 1.1.2.1: CO2 emissions by source–2012

0

50

100

150

200

250

300


North America

Middle East


Africa

158

151

58

83

214

102

93Overall 132

201220112010

Figure 1.1.1.2: CO2 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

Note: excludes emissions where the source is not specified

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1.2 Methane (CH4)

Methane is emitted from sources including process vents, gas-driven pneumatic devices and tank vents. It also escapes as fugitive emissions from process components (valves, flanges, etc.) that carry process streams containing significant quantities of methane. In addition, some methane emissions result from incomplete combustion of hydrocarbons in turbines, engines and flare equipment.

1.2.1 Emissions per unit of productionGlobal CH4 emissions normalised to hydrocarbon production for 2012 show a 7% increase compared with 2011, as indicated in Figure 1.2.1.1. This is partly due to asset acquisitions in North America and an increase in CH4 emissions in Europe.

Regional averages for methane emissions expressed per unit of production vary from 0.2 to 2.7 tonnes of methane per thousand tonnes of hydrocarbon production, as shown in Figure 1.2.1.2. In 2011 the range was between 0.2 and 2.8 tonnes per thousand tonnes of production.

Emissions intensity for Europe and the Middle East is lower than for other regions. In Europe this is partly due to low levels of flaring and venting in the region as well as to stringent regulatory controls that limit fugitive emissions. In the other regions there are higher rates of natural gas flaring and venting in certain types of production facilities.

1.2.2 Emissions by sourceThe source was specified for 36% of the total methane emissions reported in 2012.

Where the source was specified, 38% of methane emissions were from vents (including venting, vessel loading, tank storage, etc.), 33% were from fugitive losses, 24% were from flaring and 5% were from energy use, as shown in Figure 1.2.2.1.

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

2012201120102009200820072006

1.181.24

1.33

1.001.04 1.02

1.14

Figure 1.2.1.1: CH4 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

0.0

0.5

1.0

1.5

2.0

2.5

3.0


North America

Middle East


Africa

2.68

0.52 0.

61

0.16

2.58

1.21

0.83

Overall 1.3

201220112010

Figure 1.2.1.2: CH4 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

Vents 38%

Fugitive losses 33%

Flare 24%

Energy 5%

Figure 1.2.2.1: CH4 emissions by source–2012


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1.3 Greenhouse Gas (GHG)

For E&P activities, CO2 and CH4 are the principal contributors to greenhouse gas emissions, with other gases such as N2O playing a minor role. The CO2 and CH4 data presented above are used to calculate an estimate of the GHG emissions for the contributing OGP reporting companies, using the conversion to CO2 equivalent (GHG = CO2 + 21 x CH4).

1.3.1 Emissions per unit of productionParticipating companies reported normalised emissions of 160 tonnes of GHG per thousand tonnes of hydrocarbon production in 2012. This represents a 1% increase in intensity compared with 2011 results (see Figure 1.3.1.1).

Regional averages for quantity of greenhouse gas emissions per unit of production vary from 61 to 268 tonnes of greenhouse gas per thousand tonnes of hydrocarbon production, as shown in Figure 1.3.1.2. In 2011 the range was between 51 and 243 tonnes per thousand tonnes of production.

1.3.2 Emissions by sourceThe source was specified for 55% of the total reported greenhouse gas emissions.

Where the source is specified, 55% of the reported greenhouse gas emissions are from energy use, 32% are from flaring, 9% are from venting or vents and 4% are attributable to fugitive losses, as shown in Figure 1.3.2.1.

† GHG: Total Greenhouse Gases (CO2 + CH4 expressed as CO2 equivalent)

0

30

60

90

120

150

180

2012201120102009200820072006

163 164 163 159 160158 158

Figure 1.3.1.1: GHG emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

0

50

100

150

200

250

300


North America

Middle East


Africa

183 20

7

94

61

268

110

115

Overall 160

201220112010

Figure 1.3.1.2: GHG† emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

Vents 9%

Fugitive losses 4%

Flare 32%

Energy 55%

Figure 1.3.2.1: GHG emissions by source–2012


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1.4 Non-Methane Volatile Organic Compounds (NMVOCs)

NMVOC emissions mainly occur from non-combustion sources such as venting and fugitive releases (including crude oil loading). In addition, NMVOCs are emitted in the exhaust of combustion equipment and are, therefore, a function of the nature and quantity of fuel burnt, the type of combustion device used and the mode of operation.

1.4.1 Emissions per unit of productionGlobal NMVOC emissions normalised to hydrocarbon production for 2012 were 0.48 tonnes per thousand tonnes of hydrocarbon, a 2% reduction compared with 2011 results. See Figure 1.4.1.1.

Regional averages for quantity of NMVOC emitted per unit of production vary from 0.22 to 0.71 tonnes per thousand tonnes of hydrocarbon production, as shown in Figure 1.4.1.2. In 2011 the range was between 0.18 and 0.82 tonnes per thousand tonnes of production.

1.4.2 Emissions by sourceThe source was specified for 48% of the total NMVOC emissions reported in 2012.

Where the source is specified, 47% of NMVOC emissions reported for 2012 come from venting or vents, 32% from flaring, 17% from fugitive losses and 4% from energy use, as shown in Figure 1.4.2.1.

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

2012201120102009200820072006

0.50 0.49 0.48

0.700.68

0.58

0.53

Figure 1.4.1.1: NMVOC emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9


North America

Middle East


Africa

0.70

0.24

0.22

0.35

0.59

0.42

0.71

Overall 0.48

2012

2011

2010

Figure 1.4.1.2: NMVOC emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

Vents 47%

Fugitive losses 17%

Flare 32%

Energy 4%

Figure 1.4.2.1: NMVOC emissions by source–2012


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1.5 Sulphur dioxide (SO2)

Sulphur dioxide emissions by the E&P industry arise through oxidation during combustion of sulphur naturally contained within hydrocarbon fuels or flared gas. The rate of emission therefore is principally a reflection of the sulphur content of produced hydrocarbons, which varies widely depending on the nature of the hydrocarbon produced.

1.5.1 Emissions per unit of productionGlobal SO2 emissions normalised to hydrocarbon production for 2012 were 0.17 tonnes per thousand tonnes of hydrocarbon production, virtually unchanged compared with 2011 results. See Figure 1.5.1.1.

Regional averages for quantity of SO2 emissions expressed per unit of production vary from 0.03 to 0.64 tonne per thousand tonnes of hydrocarbon production, as shown in Figure 1.5.1.2. In 2011 the range was between 0.03 and 0.54 tonne per thousand tonnes of production.

1.5.2 Emissions by sourceThe source was reported for 47% of the total SO2 emissions in 2012.

Where the source was specified, 63% of sulphur dioxide emissions reported in 2012 were from flaring, 33% were from energy use and 4% were from venting or vents, as shown in Figure 1.5.2.1.

0.00

0.05

0.10

0.15

0.20

0.25

2012201120102009200820072006

0.17 0.17 0.17

0.20

0.18 0.18 0.18

Figure 1.5.1.1: SO2 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7


North America

Middle East


Africa

0.03

0.28

0.04

0.64

0.17

0.07

Overall 0.17

201220112010

0.19

Figure 1.5.1.2: SO2 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

Vents 4%

Fugitive losses0%

Flare 63%

Energy 33%

Figure 1.5.2.1: SO2 emissions by source–2012


13


©OGP

1.6 Nitrogen oxides (NOX)

Emissions of nitrogen oxides, (principally nitric oxide and nitrogen dioxide, expressed as NOX), occur almost exclusively from the combustion of natural gas or other fuels. These emissions are a function of the combustion peak temperature, and therefore of the type and operation of combustion device. NOX emissions are frequently estimated rather than measured and consequently they are strongly dependent upon the calculation methodology.

1.6.1 Emissions per unit of productionGlobal NOX emissions normalised to hydrocarbon production for 2012 were 0.43 tonnes per thousand tonnes of production, 5% higher than the 2011 result. This is largely due to an increase in drilling activity, and improved record keeping in North America. See Figure 1.6.1.1.

Normalised NOX emissions are highest in the North America region, with an average of 0.83 tonne of NOX per thousand tonnes of hydrocarbon production, reflecting the higher energy intensity. The Middle East region has the lowest normalised NOX emissions of 0.13 tonne NOX per thousand tonnes of hydrocarbon production, as shown in Figure 1.6.1.2. In 2011 the range was between 0.15 and 0.77 tonne per thousand tonnes of production.

1.6.2 Emissions by sourceThe source was reported for 46% of the total nitrogen oxide emissions reported in 2012. Where the source was specified, 94% of nitrogen oxide emissions reported in 2012 were from energy use. The remaining 6% were from flaring, as shown in Figure 1.6.2.1.

0.0

0.1

0.2

0.3

0.4

0.5

2012201120102009200820072006

0.400.38

0.41 0.41 0.410.43

0.39

Figure 1.6.1.1: NOX emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9


North America

Middle East


Africa

0.41

0.33

0.23

0.13

0.83

0.62

Overall 0.43

0.43

201220112010

Figure 1.6.1.2: NOX emissions per unit of production tonnes per thousand tonnes of hydrocarbon production

Vents 0.1%

Flare 6%

Energy 94%

Fugitive losses0%

Figure 1.6.2.1: NOX emissions by source–2012


14


©OGP

2 – Energy consumption

The energy used to produce oil and gas covers a range of activities. These include:• driving pumps that produce the hydrocarbons (and any associated produced water);• heating produced oil for separation;• producing steam for enhanced oil recovery;• driving the pumps to re-inject produced water, inject water for water-flooding and transport the

produced oil through pipelines;• powering compressors to re-inject produced gas or to export it through pipelines; and• driving turbines to generate electricity needed for operational activities, including logistics, and for

living quarters (e.g. at offshore platforms).

Energy consumption will vary widely depending upon the specific local circumstances and operational conditions. For example, mature or remote fields usually consume more energy than other fields.

In 2012, OGP reporting companies consumed on average 1.4 GigaJoules of energy for every tonne of hydrocarbon produced, as shown in Figure 2.2. This is a reduction of 9% compared with the 2011 average and reflects a change in the companies reporting data and in the number of assets operated.

As in previous years, data indicate that onshore production in 2012 was more energy intensive than offshore production.

The majority of energy requirements were met by combustion of fuels on-site rather than by purchase of electricity or steam.

Figure 2.1: Energy consumption by source—2012

Unspecified

82%Specified

18%

Purchased energy 6%

Onsite combustion 94%

15


©OGP

Figure 2.2: Energy consumed per unit of hydrocarbon production GigaJoules per tonne

0.0

0.3

0.6

0.9

1.2

1.5

1.8 Unspecified energy Purchased energy On-site combustion

2012201120102009200820072006

In Figure 2.3, the (overall) energy consumption is normalised against the quantity of hydrocarbons produced for each region. This analysis shows that operations in North America were the most energy intensive (3.39 GigaJoules per tonne of hydrocarbon produced), while the Middle East was the least energy intensive (0.24 GigaJoules per tonne).

Figure 2.3: Energy consumption per unit of hydrocarbon production—by region GigaJoules per tonne

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0


North America

Middle East


Africa

1.33

1.24

1.16

0.24

1.01

3.39

1.25

Overall 1.401.90

201220112010

16


©OGP

Flaring is the controlled burning of hydrocarbons produced in the course of petroleum exploration and production operations. It includes the controlled and safe burning of gas that, for commercial, safety or technical reasons, is not used or exported.

In 2012, 13.9 tonnes of gas were flared for every thousand tonnes of hydrocarbon produced versus 15.7 in 2011 and 16.0 in 2010, as shown in Figure 3.1.

Figure 3.1: Hydrocarbon flared per unit of hydrocarbon production tonnes per thousand tonnes

0

5

10

15

20

25

2012201120102009200820072006

23.9

20.418.8

17.616.0 15.7

13.9

Figure 3.2 shows the flaring per unit of hydrocarbon production as reported by the participating companies by region.

Figure 3.2: Hydrocarbon flared per unit of hydrocarbon production—by region tonnes per thousand tonnes

0

10

20

30

40

50

60


North America

Middle East


Africa

35.2

9

3.46

5.13

5.56

5.36

11.3

10.5

2

Overall 13.93

15.9

8

201220112010

Note: Where hydrocarbon flare could not be separated out total flare figures have been used. In most cases these metrics are similar in magnitude.

Intensities are higher in the Africa region where there is limited gas sales infrastructure. Projects in Africa that are increasing the capability to inject gas for reservoir maintenance and to deliver gas to markets, as well as a change in the companies reporting flare data, have helped reduce flaring from 53 tonnes of gas flared for every thousand tonnes of hydrocarbon produced in 2010 to 35 in 2012.

3 – Flaring

17


©OGP

Produced water is the highest volume liquid discharge generated during the production of oil and gas. It consists of formation water (present naturally in the reservoir), floodwater (previously injected into the reservoir) and/or condensed water (in the case of some gas production).

After extraction, produced water is separated and treated (de-oiled) before discharge to surface water (including seas, rivers, lakes, etc.) or to land (including to evaporation ponds). Produced water can also be injected either into the producing reservoir where it can enhance hydrocarbon recovery or into another appropriate formation for disposal. The volume of produced water typically increases as recovery of oil and gas from a field progresses that is, the field becomes ‘mature’. As context, the worldwide volume of produced water reported in this database in 2012 was approximately 1.5 times that of hydrocarbon production.

Most countries regulate the discharge of produced water taking into account differing environmental conditions and sensitivities between onshore and offshore.

The quality of produced water is most widely expressed in terms of its oil content. There are a number of analytical methodologies in use around the world for measuring oil in water. As a result of differences in analytical methodologies, care should be taken when interpreting aggregated data.

Note 1: For this analysis aqueous discharges from crude oil and natural gas facilities are categorised by the source of production and not the location where the discharges occur, in other words, where production is offshore and discharges are generated from an onshore facility, the discharges are reported as offshore .

Note 2: For various reasons companies either discharge or re-inject produced water. The split between the produced water injected and discharged changes over time and this influences the quantity and quality of oil discharged to surface.

Aqueous discharge covers the discharge of produced water, mainly produced formation water.• In 2012 participating companies reported the oil content of 786 million tonnes of discharged produced

water. Where the location was specified, approximately 89% of water discharged was from offshore operations and 11% was from onshore operations.

• For every tonne of hydrocarbon produced in 2012, 0.5 tonne of produced water was discharged to the surface and 0.9 tonne of produced water was re-injected. In 2011, 0.5 tonne of produced water was discharged to the surface and 1.0 tonne was re-injected.

• The overall average oil content of produced water discharges was 13.5 mg/l, compared with 11.9 mg/l in 2011 and 13.1 mg/l in 2010. Offshore the average oil content in produced water was 14.1 mg/l, whilst onshore it was 6.9 mg/l (see Figure 4.1.1).

• Overall 7.0 tonnes of oil was discharged per million tonnes of hydrocarbon production in 2012, a 10% increase compared with 2011 (6.3 in 2011 and 7.0 in 2010). The quantity of oil discharged per unit of hydrocarbon production was 1.9 t/106t onshore and 10.0 t/106t offshore (see Figure 4.2.1).

Note 3: There are marked differences in the scope of reporting for each region between the years, onshore and offshore.

4 – Produced Water

18


©OGP

4.1 Quality (oil content) of produced water discharges

Figure 4.1.1: Oil discharged per unit of produced water discharged milligrammes oil per litre of produced water discharged

0

5

10

15

20

OverallOnshore

6.85

Offshore

14.1

3

13.4

8

The global quantity of oil discharged per unit of produced water was 13.5 mg/l, a 14% increase compared with the 2011 result. Offshore results show a 16% increase compared with 2011. This increase is largely due to a change in the companies reporting offshore data. Onshore the average has decreased by 16% compared with 2011.

Figure 4.1.2: Oil content of produced water discharged offshore milligrammes oil per litre of produced water discharged (equivalent to tonnes per million tonnes)

0

5

10

15

20

25

30


North America

Middle EastFSUEuropeAsia/Australasia

Africa

10.5

8

Overall 14.13

8.20

36.8

8

20.0

8

13.7

3

13.6

2

201220112010

The offshore database for quality of produced water for South & Central America was affected substantially by a change in reporting scope.

A very small amount of produced water discharged was reported for the FSU and the Middle East both onshore and offshore compared with the other regions. The percentage of produced water re-injected in these regions was high, see Figures 4.3.2 and 4.3.3.

19


©OGP

Figure 4.1.3: Oil content of produced water discharged onshore milligrammes oil per litre of produced water discharged (equivalent to tonnes per million tonnes)

0

5

10

15

20

25

30


North America

Middle East


Africa

2.36

5.77

1.80

1.51

23.0

7

34.8

7

80.0

8

29.7

64 80108

Overall 6.85

201220112010

4.2 Quantity of oil discharged in produced water per unit of production

Figure 4.2.1: Oil discharged per unit of production tonnes per million tonnes of hydrocarbon production

0

3

6

9

12

15

OverallOnshoreOffshore

1.94

9.99

6.95

2012201120102009200820072006

20


©OGP

Overall the rate of oil discharged per unit of production has increased by 10% compared with 2011. This is due to an 18% increase in the reported quantity of oil discharged offshore, which is influenced by activities Africa, where new data have been introduced for 2012, and Asia/Australasia.

Regional averages for the quantity of oil discharged by unit of production of hydrocarbons vary, onshore (see Figure 4.2.3), from a few kg per million tonnes in the FSU and Middle East regions to 6.0 t/106t in Africa, while offshore (Figure 4.2.2) they vary from 0.0 t/106t in the FSU to 18.7 t/106t in Asia/Australasia.

As noted above, the difference between the overall averages onshore and offshore reflects the fact that produced water is largely re-injected onshore (where environmental sensitivities to produced water— especially salt—are generally high) while the offshore environment is generally less sensitive to produced water discharges.

Figure 4.2.2: Oil discharged per unit of production—offshore tonnes per million tonnes of hydrocarbon production

0

4

8

12

16

20


North America

Middle East


Africa

18.7

2

Overall 9.99

10.9

6

7.86

0.37

7.919.

36

201220112010

Note: A very small amount of production was reported for the FSU and the Middle East both onshore and offshore compared with the other regions. See Scope of data submissions and Section 4 of Appendix A.

Figure 4.2.3: Oil discharged per unit of production—onshore tonnes per million tonnes of hydrocarbon production

0

4

8

12

16

20


North America

Middle East


Africa

0.735.

505.95

0.15

1.42

Overall 1.94

201220112010

21


©OGP

4.3 Produced Water Injection

Figure 4.3.1: Percent of produced water re-injected overall expressed as percent. total produced water generated

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

OverallOnshoreOffshore

2012201120102009200820072006

As stated previously, produced water is often injected back into reservoirs (re-injection) to improve hydrocarbon recovery or into other geological strata for disposal.

Offshore (Figure 4.3.2), where, in the majority of locations, de-oiled produced water can be discharged to sea with limited impact, there is much less re-injection (27% in 2012). Exceptions to this include locations where injection would be beneficial to the management of the reservoir, and water chemistry allows for re-injection, or where environmental sensitivity is considered to be high.

While the average is 27% offshore there is a large variety among the regions. For example participating companies in the FSU and Middle East regions reported more than 90% of the offshore produced water re-injected, while in North America and South & Central America less than 2% of produced water was re-injected.

Onshore, where disposal to surface is often constrained by regulatory and environmental concerns, injection of produced water is the principal disposal route with 89% of water being returned below ground (see Figure 4.3.3).

Over the 3 years shown the proportion of water re-injected compared with water discharged has increased offshore and decreased onshore.

22


©OGP

Figure 4.3.2: Percentage of produced water re-injected offshore by region expressed as percent total produced water generated onshore

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Overall South & Central America

North America

Middle East


Africa

201220112010

Note: A very small amount of produced water was reported for the FSU and the Middle East both onshore and offshore compared with the other regions.

Figure 4.3.3: Percentage of produced water re-injected onshore by region expressed as percent total produced water generated offshore

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

OverallSouth & Central America

North America

Middle East


Africa

201220112010

23


©OGP

While much of the drilling in the offshore oil and gas industry is achieved using water-based drilling fluids (muds), technical challenges often require the use of non-aqueous drilling fluids (NADF) that provide higher lubricity, better performance at higher temperatures and well-bore stability compared with water-based muds. These challenges arise especially with techniques such as extended-reach and directional drilling, either or both of which may be required to develop new reservoirs or to improve recovery from previously identified resources. OGP reports non-aqueous base fluids (NABFs) according to the following classifications†:

Classification Base fluid Aromatic (%) PAH (%)

Group I Diesel and conventional mineral oil >5.0 >0.35

Group II Low toxicity mineral oil 0.5 – 5.0 0.001 – 0.35

Group III Enhanced mineral oil Synthetics (esters, olefins, paraffins)

<0.5 <0.001

In the past, diesel-based and mineral oil-based fluids (Group I fluids) were used to address these technical challenges, but it was recognised that the discharge of cuttings with adhering diesel or oil-based muds might cause adverse environmental impacts. Thus, less harmful low-toxicity mineral oil fluids (Group II, with reduced aromatic content) and later more sophisticated drilling fluids (Group III, with low to negligible aromatic content) were developed to deliver high drilling performance while ensuring that any discharges of drilling fluids adhering to cuttings or whole mud posed minimal threat to the marine environment.

Non-aqueous drilling fluids (NADF) contain more than 30% non-aqueous base fluid (NABF) as a continuous phase (typically 50%–80% by volume); the remainder consists of brine, barite and other materials such as gels and emulsifiers. The data gathered for this report relate to NABF adhering to cuttings that are discharged to the marine environment. NADFs as such are not discharged.

5.1 Non-Aqueous Base Fluid retained on cuttings discharged to sea

The following chart, Figure 5.1.1, provides a regional view of adhered base fluid quantities on cuttings discharged to the sea while drilling with NADFs. It should be noted that information on NABF discharges in 2012 has been provided by less than half (21 of 43) of the reporting companies.

Regional analysis shows that, for the companies reporting NABF retained on cuttings in 2012, cuttings with Group III fluids (18 217 tonnes, 89% of the total reported) were discharged, and that discharges of cuttings with Group II fluids were limited (4% of the total reported) and were reported only in Africa (775 tonnes) and Europe (2 tonnes). Discharges reported as “Unspecified” represented 7% (1 529 tonnes) of the total in 2012.

Absolute values rather than normalised values are shown in Figure 5.1.1. Drilling discharges are not normalised because drilling activity is not directly linked to hydrocarbon production. The number of wells that are drilled varies from year to year for various reasons including the prices of oil and natural gas as well as other economic factors. Absolute volumes reported can also vary with the number or mix of companies contributing cuttings-related data between years.

5 – Non-Aqueous Drilling Fluids retained on cuttings discharged to sea

† Classification is defined in OGP report “Environmental aspects of the use of non aqueous drilling fluids associated with offshore oil & gas operations”, Report No. 342, May 2003.

24


©OGP

Figure 5.1.1: Total base fluid (NABF) retained on cuttings discharged to the sea tonnes

0

3000

6000

9000

12000

15000

18000

21000

24000


North America

Middle East


Africa

Unspecified

Group III

Group II20

10

2011

2012

842

3 04

0

1 65

1

128 4 2

0 0 0

1 23

0

1 71

8

1 21

0 3 03

5

2 40

7

2 97

1487

4 43

6 1

20 3

69

23 8

76

14 6

88

2010

2011

2012

2010

2011

2012

2010

2011

2012

2010

2011

2012

2010

2011

2012

2010

2011

2012

Note: NABF discharges were reported by 21 of the 43 participating companies in 2012; No Group 1 NABF discharges to the sea were reported in 2008-2012.

25


©OGP

Spills are an important environmental performance indicator for the oil & gas industry since they can have a significant and visible impact on the environment. The degree of environmental impact is highly dependent on the nature of the release, where it occurred and how it was subsequently managed. Oil exploration and production companies have spill contingency plans and measures in place to respond to and mitigate spills.

For the purpose of this report a spill is defined as any loss of containment that reaches the environment (i.e. is not retained within secondary or other containment), irrespective of quantity recovered.

Spills may have a number of causes such as equipment failure (including corrosion), operating errors, and unlawful third party damage such as sabotage and theft.

The majority of spills reported by OGP member companies are oil spills, which include spills of crude, condensate and processed oil. Chemical spills with release to the external environment occur only infrequently and quantities released are generally small. Relatively few reports of chemical spills have been received and the data for these are presented in Appendix A.

6.1 Oil Spills

In 2012, companies reported a total of 7 826 oil spills. Of these, 6 146 (79%) were spills of less than one barrel in volume, amounting to a total of 89 tonnes of oil. Because of the small cumulative volume involved and, as some companies do not report spills less than 1 barrel in size, these <1 barrel size spills are not included in the detailed analysis provided below.

In 2012, 1 680 spills greater than 1 barrel in size were reported, representing a total of 9 483 tonnes of oil. Of the reported oil spills, 59% (6 401 tonnes) occurred onshore and 11% occurred offshore (1 163 tonnes). The location was not specified for the remaining 30%.

Figure 6.1.1 shows the total number of spills normalised per unit of hydrocarbon production onshore and offshore. The normalised rate for 2012 was 0.8 oil spills per million tonnes of production (1.5 in 2011, 1.4 in 2010). The normalised rate of spills onshore is higher than that offshore. The large drop in onshore spill rate is largely related to a change in companies reporting between years.

Figure 6.1.1: Number of oil spills > 1 barrel per unit of hydrocarbon production spills per million tonnes

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

OverallOffshoreOnshore

1.33

0.19 0.

84

2012201120102009200820072006

6 – Spills

26


©OGP

Figure 6.1.2 shows the number of spills normalised per unit hydrocarbon production by region. Rates for 2012 vary from 0.2 spills per million tonnes of production in the Asia/Australasia to 2.1 spills per million tonnes of production in North America.

Figure 6.1.2: Number of oil spills > 1 barrel per unit of hydrocarbon production – by region spills per million tonnes

0

1

2

3

4

5

6

7

8

9

10


North America

Middle East


Africa

0.16

0.48

0.43

0.26

0.38

9.0

1.45 Overall 0.84 2.

10

201220112010

The fall in the number and quantity of spills reported for South & Central America in 2012 compared with 2011 is due to a change in the number of companies submitting data for the region. This change is also reflected in the results for onshore spills 10–100 barrels in size as well as the overall results in Figure 6.1.1.

When normalised to hydrocarbon production (see Figure 6.1.3), spill volume rates do not show any consistent trend over the 7-year period shown. The normalised spill volume rate reported for offshore operations in 2012 was less than one fifth of the onshore rate.

Figure 6.1.3: Quantity of oil spilled per unit of hydrocarbon production tonnes per million tonnes

46.9

8

1.19

8.60

4.76

2012201120102009200820072006

0

5

10

15

20

OverallOffshore† Onshore

46.9

8

8.60

4.76

1.19

27


©OGP

The quantity of oil spilled per unit of hydrocarbon production in 2012, based on reports received, has fallen to 4.8 tonnes per million tonnes of production, 40% lower than the rate for 2011 as shown in Figure 6.1.4†. The overall drop from 2011 is mainly influenced by a reduction in the volumes of reported spills in Africa and South & Central America as well as a change in the companies reporting in South & Central America.

Figure 6.1.4: Quantity of oil spilled (spills > 1 barrel) per unit of hydrocarbon production—by region tonnes per million tonnes

0

5

10

15

20

25


North America

Middle East


Africa

2.84 0.

97

13.7

4

0.674.

33

0.36

Overall 4.76

4.21

201220112010

Figures 6.1.5 and 6.1.6 show the reported quantities of oil spilled per unit of hydrocarbon production, onshore and offshore respectively, in the different geographic regions. In Africa, reported spills greater than 1 barrel in size amounted to 3 622 tonnes of oil onshore, 285 tonnes offshore and 1 519 tonnes where the onshore/offshore breakdown was not available.

Figure 6.1.5: Quantity of oil spilled (spills > 1 barrel) per unit of hydrocarbon production onshore—by region tonnes per million tonnes

0

5

10

15

20

25


North America

Middle East


Africa

1.10 2.

05

31.7

0

4.46

53.1

132

.555

.53

15.2

4

1.404.86

Overall 8.60

201220112010

† This does not include any data related to the Deepwater Horizon incident, which is the subject of on-going, multi-district litigation. This applies to Figures 6.1.4 and 6.1.6.

28


©OGP

Figure 6.1.6: Quantity of oil spilled (spills > 1 barrel) per unit of hydrocarbon production offshore—by region tonnes per million tonnes

0

5

10

15

20

25


North America

Middle East


Africa

23.6

0.13

2.80

1.15

0.05

0.00

0.23

0.37

Overall 1.19

201220112010

The higher value in 2011 for the quantity of oil spilled offshore per unit of production in Africa, as shown in Figure 6.1.6, is dominated by a single oil spill in Nigeria in which 4.8 thousand tonnes of oil were spilled during the transfer of oil from a floating production, storage and offloading vessel to an oil tanker, 120km offshore.

Figure 6.1.7: Distribution of oil spills onshore and offshore by size number of spills

0

100

200

300

400

500

600

700

800

Unspecified> 100 bbl10 < x < 100 bbl1 < x < 10 bbl

205

32 3700

2710

69

139

681

140

340

UnspecifiedOffshoreOnshore

Figure 6.1.7 shows the distribution of spills larger than 1 barrel in terms of number of spills in each size category for 2012. In terms of number of events, the distribution is dominated by the number of spills between 1 and 10 barrels in size. However, the quantity released overall (for those spills where a size category was specified) is dominated by a few relatively large events; spills >100 barrels in size represent 77% of the total oil spilled.

In addition to the data shown in Figure 6.1.7, a total of 6 146 spills (3 157 onshore, 2 688 offshore, and 301 unspecified location) of less than 1 barrel in size were reported by participating companies.

29


©OGP

Spills greater than 100 barrels in sizeIn 2012, 106 spills in which more than 100 barrels of oil was released (69 onshore, 10 offshore, 27 unspecified location) were reported by participating companies.

Of the 106 spills, participating companies provided incident descriptions for 37 of the individual incidents. The 4 largest of the 37 were:

• 628 tonnes (~4 689 barrels) of crude oil was spilled in a single sabotage/theft incident in Nigeria.• 579 tonnes (~4 318 barrels) of crude oil was spilled in a single incident in Kuwait and was the result of a

leaking pipeline flange due to corrosion during drilling operations. 541 tonnes of the oil was recovered.• 577 tonnes (~4 304 barrels) of condensate was spilled offshore in the UK as a result of a unique

interaction of rock formation and pipe corrosion• 263 tonnes (~1 960 barrels) of crude oil leaked from a gravity line as a result of corrosion during drilling

activities in Kuwait. 246 tonnes of the oil was successfully recovered.

Figure 6.1.8: Distribution of oil spills onshore and offshore by size—2012 number of spills

Figure 6.1.9: Distribution of oil spills onshore and offshore by size—2012 quantity spilled (tonnes)

0

100

200

300

400

500

600

700

800


205

323700

2710

69

139

681

140

340

1 < x < 10 bbl10 < x < 100 bbl> 100 bblUnspecified

0

1000

2000

3000

4000

5000

6000


868

10118 00

10971007

5221

627292

53 194

1 < x < 10 bbl10 < x < 100 bbl> 100 bblUnspecified

30


©OGP

Cause (excluding intentional third party damage)A specific cause was provided for 72 spills >100 barrels in 2012. Excluding the 39 categorised as third party damage, the cause was reported for 33 of the spills >100 barrels in size, which collectively were associated with 27% of the total oil spilled (2 580 tonnes). See Figure 6.1.10.

Of the 3 spill incidents categorised as ‘other’ in 2012, 1 was the result of a road traffic accident and 2 were caused by lightning strikes.

Intentional third party damage (sabotage, theft, vandalism, etc)Incidents caused by third party damage account for 39 of the spills >100 barrels in size where the cause was reported in 2012. These third party spills represent 3 209 tonnes of oil, 34% of the total oil spilled.

Spills between 10 and 100 barrels in sizeSince 2010, detailed information has been reported for spills between 10 and 100 barrels in size.

In 2012, 376 spills in this category were reported in total (205 onshore, 32 offshore, 139 unspecified location).

The quantity of oil recovered was reported for 71% of the 10-100 barrel spills; 464 (67%) of the 693 tonnes of oil spilled in those incidents was reported to have been recovered.

Cause (excluding intentional third party damage)A specific cause was provided for 219 spills between 10 and 100 barrels in size in 2012. Of these, 194 (79%) were related to company operations or natural causes. Collectively these operational spills for which cause was provided represent 652 tonnes of oil spilled (557 tonnes of crude oil, 51 tonnes of condensate, 19 tonnes of processed oil and 26 tonnes of unspecified oil).

Figure 6.1.10 shows the distribution of cause for operational spill incidents between 10 and 100 barrels in size, where the cause was reported, for 2012.

Intentional third party damage (sabotage, theft, vandalism, etc)Incidents caused by third party damage account for 53 (24%) of the spills 10-100 barrels in size where the cause was reported in 2012. These spills caused by third parties represent 279 tonnes of oil.

Other 9%

Operator or technical error 9%

Equipment failure (excluding

corrosion) 36%

Corrosion 46%

Figure 6.1.10: Operational spills >100 barrels in size—by cause—2012 as % of spill incidents >100 barrels where cause was indicated excluding third party damage

Operator or technical error

30%

Equipment failure (excluding corrosion)

46%

Corrosion 24%

Figure 6.1.11: Operational spills 10–100 barrels in size—by cause—2012 of spill incidents 10-100 barrels where cause was indicated excluding third party damage

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Appendix A – Data tables

The following tables provide the data from which the figures and charts throughout the report are compiled.

Some of the historical results in this appendix differ from those published in OGP report 2011e, Environmental Performance Indicators report 2011 data. Results affected are:

• 2011 Africa: some hydrocarbon production, atmospheric emissions and spill data moved from onshore to offshore causing an increase in offshore production, decrease in onshore production. This affects all 2011 results where normalised by production overall, onshore and offshore, and regional results for Africa only.

• Aqueous discharges per unit of produced water discharged: calculation methodology changed in this analysis to exclude oil discharges where there was no produced water for the data set (previously oil was included where produced water discharge was reported, even if the total water discharged was zero).

• Georgia was moved from Europe to FSU region. In this report the change affects gross atmospheric emissions and energy for the two regions for the year 2011 only.

Scope of data submissions

Production associated with database and 2012 production in BP Statistical Review of World Energy—by region

Region Production in this report (106t) BP Review production (106t) Production as % of BP Review production

2012

Africa 505 644 78%

Asia/Australasia 319 821 39%

Europe 381 399 96%

FSU 113 1 370 8%

Middle East 417 1 776 23%

North America 311 1 534 20%

South & Central America 187 538 35%

Total 2 233 7 080 32%

2011

Africa 387 600 64%


Europe 452 406 111%

FSU 127 1 366 9%




Total 2 221 6 950 32%

2010

Africa 405 666 61%


Europe 474 445 107%

FSU 120 1 348 9%




Total 2 268 6 795 33%

NB: Production figures given in this report relate to ‘gross production’ whereas world data extracted from the BP Statistical Review represent ‘net production’. Thus the data are not directly comparable, but the ‘percentage of world production’ figures are given as indicative of the relative regional contributions in the database.

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No. of useable company/country data sheets/sets—by region

2012 2011 2010

Region No. of data sheets

No. of data sets No. of data sheets

No. of data sets No. of data sheets

No. of data sets

Africa 55 70 57 80 49 61

Asia/Australasia 52 71 54 70 55 68

Europe 65 85 60 77 51 68

FSU 10 11 13 14 10 11

Middle East 21 24 21 26 18 27

North America 22 32 21 30 21 33

South & Central America 27 33 28 36 24 31

Total 252 326 254 333 228 299

Data sheet: all data for one country for an individual companyData set: a set of data with distinct company, country and location (onshore/offshore/unspecified) where there is a positive return of production, emissions,

discharges, flaring, energy or spill data

Percentage of reported production included in normalised analyses

AfricaAsia/

Australasia Europe FSU Middle EastNorth

America

South & Central America All regions

Gas emissions

CO2 99% 100% 100% 100% 55% 93% 41% 85%

CH4 79% 87% 99% 100% 55% 93% 41% 79%

NMVOC 76% 75% 99% 100% 49% 100% 35% 76%

SO2 78% 87% 100% 100% 55% 100% 35% 79%

NOX 78% 99% 100% 100% 55% 100% 35% 81%

Energy consumed 97% 100% 99% 100% 92% 94% 40% 92%

Flaring 99% 85% 99% 100% 100% 99% 39% 92%

Oil discharged in produced water 69% 95% 93% 82% 57% 76% 34% 73%

Oil spills 78% 94% 97% 100% 74% 98% 100% 89%

33


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1. Gaseous emissions

Gas emissions per unit of hydrocarbon production (Figures 1.1, 1.2, 1.1.1.1, 1.2.1.1, 1.3.1.1, 1.4.1.1, 1.5.1.1, 1.6.1.1)

2012 2011 2010

Emission per 103t production

(t/103t)

Hydrocarbon production 106t


(t/103t)



(t/103t)


CO2 132.17 1 904 132.27 2 177 133.39 2 226

CH4 1.33 1 762 1.24 2 127 1.18 2 176

NMVOC 0.48 1 694 0.49 2 050 0.50 2 087

SO2 0.17 1 772 0.17 2 097 0.17 2 108

NOX 0.43 1 809 0.41 2 100 0.40 2 113

†GHG 160.05 158.23 158.08

† GHG: Total greenhouse gases (CO2 + CH4 expressed in CO2 equivalent: GHG = CO2 + 21 x CH4)NB Data only included where gas quantity and production level are both reported

Gross emissions of gases per region

AfricaAsia/


America

South & Central America Overall

2012

CO2 (106t) 78.8 49.2 31.6 11.5 13.4 61.8 7.1 253.4

CH4 (103t) 481.9 745.5 197.2 69.3 37.1 747.2 62.9 2 341.0

NMVOC (103t) 268.6 101.8 90.2 24.6 73.2 220.5 38.4 817.3

SO2 (103t) 27.9 13.1 11.1 31.8 147.3 60.5 11.4 302.9

NOX (103t) 165.8 145.1 125.0 26.4 31.6 259.8 41.9 795.7

†GHG (106t) 89.0 64.8 35.7 13.0 14.2 77.5 8.5 302.6

2011

CO2 (106t) 79.7 64.7 34.0 13.0 17.7 53.3 26.6 289.0

CH4 (103t) 565.2 861.7 185.9 72.5 58.4 648.9 237.7 2 630.3

NMVOC (103t) 305.3 196.7 98.0 22.7 87.7 180.4 120.4 1 011.1

SO2 (103t) 31.6 9.5 16.3 30.5 199.2 57.0 20.4 364.5

NOX (103t) 151.0 130.9 127.0 32.6 55.6 228.6 138.5 864.2

†GHG (106t) 91.6 82.8 37.9 14.5 19.0 67.0 31.6 344.2

2010

CO2 (106t) 83.5 68.5 35.0 10.7 16.1 54.5 29.0 297.4

CH4 (103t) 617.8 823.9 201.1 63.3 50.9 537.9 263.1 2 557.9

NMVOC (103t) 328.3 196.4 126.8 7.7 71.9 188.9 114.5 1 034.5

SO2 (103t) 41.0 13.0 19.2 30.3 176.9 64.5 17.5 362.4

NOX (103t) 152.6 150.0 119.6 26.4 47.0 223.6 141.0 860.2

†GHG (106t) 96.5 85.8 39.3 12.0 17.2 65.8 34.6 351.1

† GHG: Total greenhouse gases (CO2 + CH4 expressed in CO2 equivalent: GHG = CO2 + 21 x CH4)

34


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Emissions per unit of hydrocarbon production (tonnes per thousand tonnes)—by region (Figures 1.1.1.2 1.2.1.2, 1.3.1.2, 1.4.1.2, 1.5.1.2, 1.6.1.2)

AfricaAsia/


EastNorth

America


2012

CO2 emissions (t/103t) 158.00 150.53 82.63 102.13 57.87 213.61 92.91 132.17

Production (106t) 498 319 380 113 230 289 76 1 904

CH4 emissions (t/103t) 1.21 2.68 0.52 0.61 0.16 2.58 0.83 1.33

Production (106t) 398 278 379 113 230 289 76 1 762

NMVOC emissions (t/103t) 0.70 0.42 0.24 0.22 0.35 0.71 0.59 0.48

Production (106t) 386 238 376 113 206 311 65 1 694

SO2 emissions (t/103t) 0.07 0.04 0.03 0.28 0.64 0.19 0.17 0.17

Production (106t) 394 279 380 113 229 311 66 1 772

NOX emissions (t/103t) 0.41 0.43 0.33 0.23 0.13 0.83 0.62 0.43

Production (106t) 394 316 380 113 230 311 66 1 809

†GHG emissions (t/103t) 183.40 206.87 93.57 115.02 61.25 267.88 110.28 160.05

2011

CO2 emissions (t/103t) 205.78 183.53 74.95 99.95 47.48 180.57 136.11 132.27

Production (106t) 387 351 452 127 371 295 194 2 177

CH4 emissions (t/103t) 1.46 2.81 0.41 0.59 0.16 2.20 1.22 1.24

Production (106t) 387 307 451 123 371 295 194 2 127


Production (106t) 372 274 448 122 347 295 193 2 050

SO2 emissions (t/103t) 0.08 0.03 0.04 0.24 0.54 0.19 0.10 0.17

Production (106t) 382 277 452 126 371 295 194 2 097

NOX emissions (t/103t) 0.39 0.47 0.28 0.24 0.15 0.77 0.71 0.41

Production (106t) 382 280 452 126 371 295 194 2 100

†GHG emissions (t/103t) 236.49 242.51 83.61 112.30 50.76 226.72 161.80 158.23

2010

CO2 emissions (t/103t) 205.98 1,77.24 73.67 88.78 51.76 165.88 143.51 133.39

Production (106t) 405 386 474 120 310 328 202 2 226

CH4 emissions (t/103t) 1.53 2.45 0.42 0.53 0.16 1.64 1.30 1.18

Production (106t) 405 336 474 120 310 328 202 2 176


Production (106t) 404 279 474 120 287 322 202 2 087

SO2 emissions (t/103t) 0.10 0.05 0.04 0.25 0.57 0.20 0.09 0.17

Production (106t) 404 276 474 120 310 322 201 2 108

NOX emissions (t/103t) 0.37 0.53 0.25 0.22 0.15 0.69 0.69 0.40

Production (106t) 404 281 474 120 310 322 202 2 113

†GHG emissions (t/103t) 238.11 228.69 82.49 99.91 55.12 200.32 170.81 158.08

† GHG: Total greenhouse gases (CO2 + CH4 expressed in CO2 equivalent: GHG = CO2 + 21 x CH4)NB Data only included where gas quantity and production level are both reported

35


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Gas emissions by source (Figures 1.1.2.1, 1.2.2.1, 1.3.2.1, 1.4.2.1, 1.5.2.1, 1.6.2.1)

Energy Flare Fugitive losses Vents Other/unspecified E&P

Overall

2012

CO2 (106t) 91.08 48.62 0.03 8.94 104.74 253.41

CH4 (103t) 45.46 197.28 271.89 322.02 1 504.37 2 341.02

NMVOC (103t) 16.74 123.93 65.64 184.79 426.20 817.30

SO2 (103t) 46.53 90.72 0.00 5.79 159.86 302.91

NOX (103t) 342.10 21.97 0.00 0.19 431.42 795.67

†GHG (106t) 92.04 52.76 5.74 15.70 136.33 302.57

2011

CO2 (106t) 92.07 57.07 0.03 8.09 131.72 288.98

CH4 (103t) 192.44 384.45 384.90 462.56 1 205.95 2 630.30

NMVOC (103t) 15.84 138.42 76.02 197.36 583.50 1 011.13

SO2 (103t) 50.54 115.59 4.70 12.28 181.35 364.46

NOX (103t) 388.14 29.94 0.00 0.16 445.96 864.20

†GHG (106t) 96.11 65.15 8.11 17.81 157.05 344.22

2010

CO2 (106t) 95.64 63.83 0.15 6.47 131.27 297.37

CH4 (103t) 190.45 375.56 280.52 590.00 1 121.40 2 557.93

NMVOC (103t) 19.43 183.50 55.27 153.21 623.13 1 034.53

SO2 (103t) 49.77 110.51 0.02 4.10 197.97 362.37

NOX (103t) 387.16 32.13 0.03 1.09 439.82 860.22

†GHG (106t) 99.64 71.72 6.04 18.86 154.82 351.08

Gas emissions in production activities per unit of hydrocarbon production (tonnes per thousand tonnes)—onshore and offshore

CO2 CH4 NMVOC SO2 NOX GHG†

Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore

2012

Emissions (t/103t) 116.93 134.15 1.48 0.77 0.61 0.45 0.30 0.12 0.52 0.37 143.22 149.78

Production (106t) 669 975 565 937 546 922 575 971 579 971 669 975

2011

Emissions (t/103t) 142.73 126.50 1.52 1.12 0.65 0.45 0.32 0.10 0.52 0.35 174.48 149.12

Production (106t) 745 1 230 740 1 185 709 1 139 739 1 156 742 1 156 745 1 230

2010

Emissions (t/103t) 134 125.00 1.20 1.13 0.61 0.45 0.27 0.11 0.46 0.34 159.16 147.83

Production (106t) 835 1 211 832 1 164 802 1 106 822 1 106 828 1 106 835 1 211

NB Data only included where gas quantities in production activities and production levels are both reported† GHG: Total greenhouse gases (CO2 + CH4 expressed in CO2 equivalent: GHG = CO2 + 21 x CH4)

36


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2. Energy Consumption

Energy consumption per unit of hydrocarbon production (Figure 2.1, 2.2)

2012 2011 2010 2009 2008

% Onsite combustion 76 81 80 80 79

% Purchased 5 5 5 5 4

% Unspecified 19 16 16 16 17

Total energy consumption (GJ/t) 1.40 1.54 1.47 1.48 1.40

Production (106t) 2 047 2 024 2 092 2 151 2 049

NB Data only included where energy consumption and production level are both reported.

Gross energy consumption (million GigaJoule)—by region

Onsite Purchased Unspecified Total

2012

Africa 382.05 19.74 91.68 493.47

Asia/Australasia 362.11 10.06 237.12 609.29

Europe 422.47 38.75 7.24 468.46

FSU 88.67 0.74 41.99 131.39

Middle East 40.55 27.48 25.39 93.41

North America 822.36 54.94 112.18 989.48

South & Central America 85.68 0.55 8.17 94.40

2011

Africa 355.47 16.24 88.52 460.24


Europe 468.41 30.20 7.82 506.43

FSU 96.62 0.92 43.82 141.35

Middle East 154.33 12.06 15.96 182.35

North America 729.34 54.35 116.22 899.91


2010

Africa 366.88 15.14 84.64 466.66


Europe 475.16 27.58 8.26 511.01

FSU 90.15 1.56 42.26 133.96

Middle East 83.48 8.35 16.78 108.62

North America 749.8 75.3 122.7 947.8


37


©OGP

Energy consumption per unit of hydrocarbon production (GigaJoules per tonne)—by region (Figure 2.3)

AfricaAsia/


EastNorth

America


2012

% Onsite combustion 77.4 59.2 90.2 67.5 42.4 83.1 90.7 76.5

% Purchased 4.0 1.7 8.3 0.6 29.9 5.6 0.6 5.3

% Unspecified 18.6 39.2 1.6 32.0 27.7 11.3 8.7 18.3

Total energy consumption (GJ/t) 1.01 1.90 1.24 1.16 0.24 3.39 1.25 1.40

Production (106t) 490 319 376 113 383 292 75 2 047

2011


% Purchased 3.5 1.5 6.0 0.7 6.6 6.0 3.1 4.3

% Unspecified 19.3 32.1 1.6 32.1 8.8 12.9 3.5 15.3


Production (106t) 387 350 444 123 233 294 194 2 024

2010


% Purchased 3.3 1.7 5.4 1.2 7.7 8.0 2.8 4.8

% Unspecified 18.2 34.1 1.6 31.6 15.5 13.0 2.6 15.4


Production (106t) 401 386 473 120 181 328 202 2 092

NB Data only included where energy and production level are both reported. Production is the total HC production for data sets where one of onsite, purchased or unspecified energy is reported.

Energy consumption per unit of hydrocarbon production (GigaJoules per tonne)—onshore and offshore

2012 2011 2010

Onshore (GJ/t) 1.60 2.24 2.07

Offshore (GJ/t) 1.21 1.23 1.10

Unspecified (GJ/t) 1.47 1.30 1.65

Overall (GJ/t) 1.40 1.54 1.47

NB Data only included where energy and production levels are both reported

3. Flaring

Hydrocarbon flared per unit of production (tonnes per thousand tonnes) (Figure 3.1.)

2012 2011 2010 2009 2008 2007 2006

Hydrocarbon flared t/103 tonnes 13.93 15.73 16.02 17.59 18.75 20.44 23.9

Production 106 tonnes 2 071 2 176 2 235 2 327 2 080 2 041 1 735

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Flaring per unit of hydrocarbon production (tonnes per thousand tonnes)—by region (Figure 3.2)

AfricaAsia/


EastNorth

America


2012

Total flared (t/103t) 35.29 15.98 3.46 10.52 5.13 5.56 5.36 13.93

Production (106t) 498 284 378 113 416 308 73 2 071

2011

Total flared (t/103t) 50.73 17.56 3.64 11.69 6.43 3.42 11.29 15.73

Production (106t) 382 345 443 121 410 283 193 2 176

2010

Total flared (t/103t) 52.93 15.11 3.96 7.51 8.50 2.26 13.01 16.02

Production (106t) 400 366 471 119 352 326 202 2 355

NB Data only included where flaring and production levels are both reported

4. Produced Water

Oil discharged per unit of produced water discharged (milligrammes oil per litre of produced water discharged) (Figure 4.1.1)

2012 2011 2010 2009 2008 2007 2006

Onshore 6.85 8.12 14.24 11.60 12.80 17.49 7.71

Offshore 14.13 12.22 12.85 13.64 14.84 15.48 17.47

Unspecified 15.82 14.56 14.60 12.98 21.64 18.84 24.86

Overall 13.48 11.85 13.14 13.34 14.77 15.84 16.40

NB Data only included where oil in produced water and produced water quantity are both reported

39


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Oil content of produced water discharged (Figures 4.1.2, 4.1.3)

AfricaAsia/


America


2012

Onshore

Oil discharged (t/106t) 2.36 5.77 1.80 0.00 0.00 23.07 1.51 6.85

PW discharged (106t) 7.99 58.43 4.37 0.10 0.01 8.44 2.84 82.19

Offshore


PW discharged (106t) 128.16 268.95 214.44 0.09 5.75 27.48 6.75 651.61

Unspecified

Oil discharged (t/106t) 10.63 25.30 0.00 no data no data 12.11 no data 15.82

Production (106t) 24.84 18.13 0.60 no data no data 9.02 no data 52.60

Overall


PW discharged (106t) 160.99 345.51 219.41 0.19 5.76 44.94 9.60 786.39

Total PW (106t)† 198 914 343 6 178 312 77 2 027

2011

Onshore


PW discharged (106t) 1.58 73.63 4.62 1.19 0.02 13.23 6.74 101.01

Offshore


PW discharged (106t) 106.94 280.06 222.23 0.05 8.12 31.98 108.27 757.65

Unspecified


Production (106t) 26.18 1.20 0.21 no data no data 6.92 no data 34.51

Overall


PW discharged (106t) 134.69 354.90 227.06 1.24 8.14 52.13 115.00 893.17

Total PW (106t)† 172 891 368 5 230 295 378 2 339

2010

Onshore


PW discharged (106t) 16.29 90.23 4.57 0.16 0.20 22.15 0.61 134.21

Offshore


PW discharged (106t) 117.73 294.37 269.79 0.02 6.54 33.67 112.36 834.47

Unspecified


Production (106t) 27.63 28.54 0.39 0.00 no data 12.12 no data 68.69

Overall


PW discharged (106t) 161.66 413.14 274.75 0.18 6.74 67.94 112.96 1 037.37

Total PW (106t)† 225 1 049 443 3 250 370 334 2 674

NB Data only included where oil discharges and produced water discharges are both reported† Includes produced water re-injected + produced water discharged where oil content and either water re-injected or discharged are reported

40


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Oil discharged per unit of hydrocarbon production (tonnes per million tonnes) (Figure 4.2.1)

2012 2011 2010 2009 2008 2007 2006

Onshore 1.94 2.41 3.16 3.02 3.62 5.65 2.04

Offshore 9.99 8.49 9.14 10.17 11.08 12.18 13.43

Overall 6.95 6.33 6.99 7.48 8.54 9.77 9.64

Oil discharged per unit of hydrocarbon production—by region (Figures 4.2.2, 4.2.3)

AfricaAsia/


America


2012

Onshore


Production (106t) 57 61 11 52 110 140 28 459

Offshore


Production (106t) 241 200 274 41 128 48 36 967

Unspecified


Production (106t) 48 40 68 no data no data 51 no data 207

Overall


Production (106t) 346 302 352 93 237 238 64 1 633

2011

Onshore


Production (106t) 65 71 21 44 114 141 50 506

Offshore


Production (106t) 229 258 342 43 134 65 141 1211

Unspecified

Oil discharged (t/106t) 4.35 1.82 0.02 0.00 no data 6.62 no data 2.97

Production (106t) 59 8 68 10 no data 43 no data 189

Overall


Production (106t) 353 337 431 97 248 249 191 1 906

2010

Onshore


Production (106t) 69 74 80 52 111 177 43 607

Offshore


Production (106t) 244 267 367 50 51 53 142 1 173

Unspecified

Oil discharged (t/106t) 4.78 19.07 0.00 0.00 no data 3.62 no data 5.87


Overall


Production (106t) 392 364 458 111 162 278 185 1 951

NB Data only included where oil discharges and production level are both reported

41


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Percent of produced water re-injected overall (expressed as percent total produced water generated†) (Figure 4.3.1)

2012 2011 2010 2009 2008 2007 2006

Onshore 89 90 90 89 88 89 90

Offshore 27 23 22 18 17 16 19

Unspecified 33 42 42 41 11 25 22

Overall 66 65 65 63 63 64 61

† total produced water generated: produced water discharged + produced water re-injected

Percent of produced water re-injected overall (expressed as percent total produced water generated†)—by region (Figures 4.3.2, 4.3.3)

AfricaAsia/


America


2012

Onshore 92 90 92 97 74 97 99

Offshore 18 18 30 97 90 2 0

Unspecified 28 80 71 no data no data 1 no data

Overall 26 67 42 97 77 89 90

2011

Onshore 84 87 94 65 81 95 97

Offshore 19 14 29 97 84 0 12

Unspecified 34 86 87 no data no data no data no data

Overall 27 63 44 73 82 86 70

2010

Onshore 90 87 94 88 85 93 100

Offshore 10 17 31 98 82 3 5

Unspecified 35 75 81 98 no data 39 no data

Overall 36 65 43 93 85 85 67

† total produced water generated: produced water discharged + produced water re-injected

42


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Ratio of produced water re-injected to produced water discharged† (tonnes per tonne)—by region

AfricaAsia/


America


2012

Onshore

PW re-injected (t/t) 11.65 8.74 11.27 31.19 2.87 31.56 104.28 8.02

Offshore

PW re-injected (t/t) 0.22 0.21 0.43 28.05 8.96 0.02 0.00 0.38

Unspecified

PW re-injected (t/t) 0.38 3.91 2.46 no data no data 0.01 no data 0.49

Overall

PW re-injected (t/t) 0.35 1.99 0.72 29.74 3.38 8.12 9.37 1.93

2011

Onshore

PW re-injected (t/t) 5.09 6.73 14.54 1.84 4.38 18.33 38.32 8.54

Offshore

PW re-injected (t/t) 0.24 0.16 0.40 32.37 5.41 0.00 0.14 0.30

Unspecified

PW re-injected (t/t) 0.51 6.29 6.55 no data no data no data no data 0.72

Overall

PW re-injected (t/t) 0.36 1.73 0.78 2.71 4.53 6.03 2.38 1.84

2010

Onshore

PW re-injected (t/t) 8.80 6.43 15.19 7.27 5.66 13.57 374.04 8.80

Offshore

PW re-injected (t/t) 0.12 0.21 0.45 50.91 4.54 0.03 0.05 0.28

Unspecified

PW re-injected (t/t) 0.54 3.07 4.33 42.13 no data 0.64 no data 0.71

Overall

PW re-injected (t/t) 0.56 1.84 0.76 13.42 5.51 5.86 2.05 1.89

† Produced water re-injected/produced water discharged where both re-injected and discharged produced water, as well as hydrocarbon production, are reported

NB Data only included where quantities of both re-injected and discharged produced water, as well as hydrocarbon production, are reported

43


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Produced water re-injected per unit of hydrocarbon production (tonnes per tonne)—by region

AfricaAsia/


America


2012

Onshore

Produced water (t/t) 0.09 7.70 3.92 0.06 0.63 2.11 3.77 1.70

Production (106t) 117.11 67.43 16.14 53.28 288.03 160.56 38.22 740.77

Offshore


Production (106t) 163.50 118.84 213.01 40.63 127.57 33.29 27.34 724.17

Unspecified

Produced water (t/t) 0.18 0.29 0.31 0.01 no data 0.00 no data 0.18


Overall


Production (106t) 355.56 194.27 244.96 104.02 415.60 197.46 65.56 1 577.43

2011

Onshore


Production (106t) 19.46 75.65 17.32 46.00 271.43 150.05 51.08 630.99

Offshore


Production (106t) 150.20 155.02 289.92 42.99 133.87 41.35 127.80 941.15

Unspecified

Produced water (t/t) 0.22 0.39 0.36 0.01 no data no data no data 0.23

Production (106t) 43.31 7.19 13.12 9.70 no data no data no data 73.32

Overall


Production (106t) 212.97 237.86 320.36 98.69 405.30 191.39 178.88 1 645.46

2010

Onshore


Production (106t) 25.59 81.80 75.06 52.71 260.72 194.05 60.19 750.11

Offshore


Production (106t) 157.57 182.44 329.62 49.53 80.26 37.16 141.02 977.60

Unspecified

Produced water (t/t) 0.19 0.34 0.15 0.01 no data 0.09 no data 0.16


Overall


Production (106t) 243.60 272.51 416.01 111.39 340.98 255.51 201.21 1 841.22

NB Data only included where quantities of both produced water re-injected and production are reported

44


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Total oil discharged (discharges + spills) per unit of hydrocarbon production

2012 2011 2010

Total oil discharged per 106t production

(t/106t)



(t/106t)



(t/106t)


Onshore 12 452 18 479 12 593

Offshore 12 845 15 1 030 10 1112

Unspecified 13 207 10 186 26 157

Overall 12 1 504 15 1 694 12 1 862

NB For onshore, offshore, unspecified and overall results data are only included where oil in produced water and spills are reported as well as production levels for the dataset.

5. Non-Aqueous Drilling Fluids retained on cuttings discharged to sea

Total base fluid (NABF) retained on cuttings discharged to sea—by region (tonnes) (Figure 5.1.1)

AfricaAsia/


America


2012

Group I 0 0 0 0 0 0 0 0

Group II 775 0 2 0 0 0 0 777

Group III 406 14 688 0 0 0 1 210 1 913 1 7938

Unspecified 470 0 0 1 0 0 1 058 1 808

Total 1 651 14 688 2 1 0 1 210 2 971 20 523

2011

Group I 0 0 0 0 0 0 0 0

Group II 615 0 4 0 0 0 0 619

Group III 2 388 13 727 0 4 436 0 1 595 1 917 24 063

Unspecified 37 10 149 0 0 0 123 490 10 799

Total 3 040 23 876 4 4 436 0 1 718 2 407 35 481

2010

Group I 0 0 0 0 0 0 0 0

Group II 352 0 1 0 0 0 0 353

Group III 417 17 867 127 0 0 1 088 2 075 21 574

Unspecified 73 2 502 0 487 0 142 960 4 164

Total 842 20 369 128 487 0 1 230 3 035 26 091

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6. Spills

Number of oil spills >1 barrel in size and quantity spilled per unit of hydrocarbon production (Figure 6.1.1, 6.1.3)

2012 2011 2010 2009 2008 2007 2006 2005

Onshore

Number of spills (t/106t) 1.33 3.65 3.10 3.47 3.31 3.37 3.48 3.12

Quantity spilt (t/106t) 8.6 11.97 7.16 46.98 18.27 10.67 16.95 7.87

Production (106t) 737 694 798 747 747 742 778 808

Offshore



Production (106t) 976 1 114 1 174 1 193 1 203 1 042 1 075 1 044

Unspecified



Production (106t) 265 199 166 178 126 129 118 201

Overall



Production (106t) 1 977 2 006 2 139 2 117 2 075 1 913 1 971 2 053

NB: Data only included where quantity of oil spilt and production level are both reported. Excludes spills <1 barrel in size

Number of oil spills >1 barrel in size and quantity spilled per unit of hydrocarbon production—by region (Figures 6.1.2, 6.1.4)

AfricaAsia/


America


2012



Production (106t) 393 301 370 113 308 306 187 1 977

2011

Number of spills (t/106t) 1.37 0.17 0.43 0.12 0.44 1.65 9 1.51


Production (106t) 386 309 430 121 304 271 184 2 006

2010



Production (106t) 398 334 461 111 329 313 194 2 139

NB: Excludes spills <1 barrel in size

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Number of oil spills >1 barrel in size and quantity spilled per unit of hydrocarbon production—by region (Figure 6.1.5, 6.1.6)

AfricaAsia/


America


2012Onshore



Production (106t) 65 73 16 53 266 209 54 737

OffshoreNumber of spills (t/106t) 0.24 0.08 0.30 0.00 0.10 0.15 0.08 0.19


Production (106t) 248 183 283 41 42 47 133 976

UnspecifiedNumber of spills (t/106t) 3.73 0.11 0.08 0.11 no data 3.83 no data 1.91

Quantity spilt (t/106t) 18.98 0.06 0.19 0.04 no data 7.58 no data 7.23


OverallNumber of spills (t/106t) 1.45 0.16 0.48 0.26 0.38 2.10 0.43 0.84


Production (106t) 393 301 370 113 308 306 187 1 977

2011Onshore



Production (106t) 75 56 25 58 254 176 50 694



Production (106t) 250 248 336 43 50 52 134 1 114






Production (106t) 386 309 430 121 304 271 184 2 006

2010Onshore



Production (106t) 66 84 75 53 248 214 59 798



Production (106t) 253 231 375 50 80 51 134 1174






Production (106t) 398 334 461 111 329 313 194 2 139

NB Data only included for production level where oil quantities spilled and production are reported Excludes spills <1 barrel in size

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Quantity of oil spilled per spill onshore and offshore (tonnes)—by region

AfricaAsia/


America


2012

Onshore

Average size (t) 16.8 2.4 2.8 4.0 11.3 2.1 1.6 6.5

Quantity spilt (t) 3 622 88 245 109 1 292 933 112 6 401

Offshore

Average size (t) 4.7 1.7 9.2 no data 0.5 1.5 4.5 6.4

Quantity spilt (t) 285 23 793 0 2 11 49 1 163

Unspecified

Average size (t) 5.1 0.5 2.3 0.3 no data 2.0 no data 3.8

Quantity spilt (t) 1 519 3 14 1 no data 384 0 1 919

2011

Onshore

Average size (t) 10.3 1.2 1.8 1.0 23.5 2.5 1.0 3.3

Quantity spilt (t) 2 448 25 187 14 3 128 928 1 590 8 319

Offshore


Quantity spilt (t) 5 529 114 257 0 1 2 328 6 231

Unspecified


Quantity spilt (t) 1 219 4 21 0 0 142 0 1 386

2010

Onshore

Average size (t) 18.6 8.5 1.0 1.8 1.8 1.7 0.5 2.3

Quantity spilt (t) 3 572 407 104 27 197 727 763 5 796

Offshore

Average size (t) 7.7 4.2 4.5 7.1 0.9 0.5 3.5 5.3

Quantity spilt (t) 464 110 212 36 8 5 21 856

Unspecified


Quantity spilt (t) 2 968 6 11 2 0 102 0 3 089

NB: Excludes spills <1 barrel in size

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Distribution of oil spills onshore and offshore by size (Figure 6.1.7, 6.1.8, 6.1.9)

<1 barrel 1<X<10 barrel10<X<100

barrel >100 barrel Unspecified Overall†

2012

Onshore

Number 3 157 681 205 69 37 992

Quantity (t) 50 292 868 5221 18 6 401

Offshore

Number 2 688 140 32 10 0 182

Quantity (t) 31 53 101 1007 0 1163

Unspecified

Number 301 340 139 27 0 506

Quantity (t) 7 194 627 1 097 0 1 920

Overall

Number 6 146 1161 376 106 37 1 680

Quantity (t) 89 540 1 598 7 327 18 9 483

2011

Onshore

Number 2 728 2 273 181 61 20 2 535

Quantity (t) 38 1 788 862 5 668 0 8 318

Offshore

Number 986 161 30 9 17 217

Quantity (t) 15 68 100 6 060 3 6 231

Unspecified

Number 247 225 38 20 0 283

Quantity (t) 4 127 153 1 106 0 1 386

Overall

Number 3 961 2 659 249 90 37 3 035

Quantity (t) 57 1 984 1 115 12 834 3 15 936

2010

Onshore

Number 2 705 2 197 193 60 31 2 481

Quantity (t) 50 813 875 4 061 48 5 797

Offshore

Number 1 471 108 28 15 11 162

Quantity (t) 16 44 118 692 2 856

Unspecified

Number 140 264 44 24 0 332

Quantity (t) 7 126 173 2 789 0 3 088

Overall

Number 4 316 2 569 265 99 42 2 975

Quantity (t) 74 983 1 166 7 542 50 9 741

†Excludes spills <1 barrel in size

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Distribution of oil spills by size—by region

<1 barrel 1<X<10 barrel10<X<100

barrel >100 barrel Unspecified Overall†

2012

Africa Number 668 341 165 69 0 575

Quantity (t) 16.6 201.0 757.5 4 466.9 0.0 5 425.3

Asia/Australasia Number 361 41 12 2 0 55

Quantity (t) 4.4 19.8 49.4 44.6 0.0 113.7

Europe Number 3797 152 20 7 0 179

Quantity (t) 43.5 50.3 81.7 920.0 0.0 1 052.0

FSU Number 32 20 8 1 0 29

Quantity (t) 0.9 11.0 43.8 54.8 0.0 109.6

Middle East Number 29 66 20 6 26 118

Quantity (t) 0.8 32.7 68.0 1 193.0 0.0 1 293.7

North America Number 635 478 135 18 11 642

Quantity (t) 9.9 196.6 542.2 571.0 18.0 1 327.7

South & Central America Number 624 63 16 3 0 82

Quantity (t) 12.8 28.8 55.7 76.5 0.0 161.0

2011

Africa Number 635 372 98 62 1 533

Quantity (t) 13.6 192.3 508.9 8 493.5 0.3 9 195.0


Quantity (t) 4.7 21.8 23.8 96.7 0.3 142.7

Europe Number 2251 149 18 6 12 185

Quantity (t) 25.9 58.2 56.3 348.6 2.5 465.6

FSU Number 56 13 2 0 0 15

Quantity (t) 1.1 6.6 7.1 0.0 0.0 13.7


Quantity (t) 1.5 39.4 89.8 3 000.3 0.0 3 129.5


Quantity (t) 9.6 201.5 374.1 495.9 0.0 1 071.5

South & Central America Number 31 1642 15 2 0 1 659

Quantity (t) 0.6 1 464.0 54.7 398.8 0.0 1 917.5

2010

Africa Number 410 323 98 70 15 506

Quantity (t) 12.7 154.2 460.6 6 380.6 8.0 7 003.3


Quantity (t) 4.8 25.7 78.4 419.1 0.3 523.4

Europe Number 2 560 129 17 5 5 156

Quantity (t) 39.5 40.4 73.6 211.8 1.3 327.2

FSU Number 69 15 3 3 0 21

Quantity (t) 2.3 9.9 6.7 48.4 0.0 65.0


Quantity (t) 1.2 38.9 75.4 89.9 0.0 204.3

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Quantity (t) 13.1 165.5 464.1 164.4 40.2 834.3

South & Central America Number 87 1 577 3 4 0 1 584

Quantity (t) 0.2 548.4 7.4 227.5 0.0 783.3

†Excludes spills <1 barrel in size

Oil spills >100 barrels in size (where cause was indicated)—by cause (Figure 6.1.10)

Number of spillsLoss from primary

containment (tonnes)

Recovered (tonnes)†

Corrosion 15 1 784 916

Equipment failure (excluding corrosion) 12 607 284

Operator or technical error 3 69 51

Third party damage (sabotage, theft, vandalism, etc.) 39 3 209 620

Other (1 road accident, 2 lightening strike) 3 120 18

Total 72 5 789 1 889

†Quantity of oil recovered is not reported for all spills

Oil spills 10–100 barrels (where cause was indicated)—by cause (Figure 6.1.11)



Corrosion 40 137

Equipment failure (excluding corrosion) 77 323

Operator or technical error 49 192

Third party damage (sabotage, theft, vandalism, etc.) 53 279

Other 23 87

Unknown 5 22

Oil spills 10–100 barrels 2011 (where cause was indicated)—by materials spilled



Crude oil 158 646

Condensate 18 66

Processed oil 7 9

Unspecified oil 64 310

Oil spills 10–100 barrels 2011 (where cause was indicated)—by region



Africa 73 334

Asia/Australasia 10 40

Europe 9 41

FSU 5 28

Middle East 17 56

North America 117 484

South & Central America 16 56

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Oil spills 10–100 barrels (where cause was indicated)—by location



Onshore 224 973

Offshore 23 66

Chemical spills (tonnes) onshore and offshore—by region†

AfricaAsia/


America


2012

Onshore

Average size (t) 16.13 0.52 0.35 3.60 6.62 3.92 0.80 4.19

Quantity spilt (t) 113 2 0 29 33 607 7 791

Offshore

Average size (t) 3.02 0.54 4.22 37.58 0.64 6.11 11.94 6.95

Quantity spilt (t) 27 3 401 225 1 122 430 1 210

Overall


Quantity spilt (t) 67 1 7 1 no data 237 0 312

2011

Onshore

Average size (t) 55.76 1.16 2.23 31.27 0.08 1.52 11.83 6.91

Quantity spilt (t) 390 22 9 281 0 152 272 1 127

Offshore

Average size (t) 0.78 4.28 3.13 7.00 no data 3.44 12.58 4.70

Quantity spilt (t) 7 47 282 7 0 72 327 742

Unspecified

Average size (t) 2.93 14.31 no data no data no data 1.82 no data 3.21

Quantity spilt (t) 15 14 0 0 0 13 0 42

2010

Onshore

Average size (t) 9.75 8.27 0.74 1.03 0.72 1.89 0.94 3.18

Quantity spilt (t) 205 41 1 2 3 176 10 439

Offshore


Quantity spilt (t) 28 35 6,432 0 2 27 273 6 798

Unspecified

Average size (t) 15.71 0.19 no data no data no data 2.75 no data 8.22

Quantity spilt (t) 63 0 0 0 0 11 0 74

† Excludes spills <1 barrel in size

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APIAmerican Petroleum Institute.

Bbl, BarrelIn the energy industry, a barrel is 42 U.S. gallons measured at 60° Fahrenheit. This is approximately 159 litres.

Base fluidThe continuous phase or suspending medium of a drilling fluid formulation.

CH4Methane, the principal constituent of natural gas. One of the primary greenhouse gases.

CO2Carbon dioxide, a colourless, odourless and non-flammable gas. CO2 emissions occur from the combustion of fossil fuels. CO2 is a primary greenhouse gas.

Crude oilA mixture of hydrocarbons that exists as a liquid in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities. Crude oil is the raw material that is refined into gasoline, heating oil, jet fuel, propane, petrochemicals, and other products.

CuttingsThe particles generated by drilling into subsurface geologic formations and carried out from the wellbore with the drilling fluid. Examples of drill cuttings include small pieces of rock varying in size and texture from fine silt to gravel.

Drilling fluidThe circulating fluid (mud) used in the rotary drilling of wells to clean and condition the hole and to counterbalance formation pressure. A water-based drilling fluid is the conventional drilling fluid in which water is the continuous phase and the suspending medium for solids, whether or not oil is present. An oil-base drilling fluid has diesel, crude, or some other oil as its continuous phase with water as the dispersed phase.

E&PExploration and Production (of hydrocarbons).

Emission rateEmissions of gases per unit of hydrocarbon production.

Energy (as an atmospheric emission source category)Includes emissions generated through the consumption of fuel. Typical fuel-consuming equipment types in E&P operations include: turbines (e.g., driving compressors, generators, pumps); internal combustion engines; heaters; and boilers/reboilers.

Energy intensityEnergy consumed per unit of hydrocarbon production.

ExplorationStudy of geological formations to detect the presence of hydrocarbons.

Flare (as an atmospheric emission source category)Includes emissions generated by burning of gases (or in some cases liquids) in a thermal destruction device, including E&P flaring of associated gas (and in some cases liquids) from oil production or well testing. Typical equipment sources in this category include flares and thermal oxidisers.

FlaringThe controlled burning of natural gas produced in association with oil in the course of oil and gas exploration and production operations. It also includes the controlled and safe burning of gas that cannot be used for commercial or technical reasons.

Fugitive emission, fugitive lossesUnintended emissions released to the air, other than those from stacks or vents from the processing, transmission, and/or transportation of fossil fuels. They are often due to equipment leaks and evaporative processes.

Gas-oil ratio The volume of gas at atmospheric pressure produced per unit volume of oil produced.

Gaseous emissionGaseous emissions to the atmosphere from flaring and venting, process and turbine combustion. Includes fugitive losses from pumps, valves, flanges, pipes, etc.

Greenhouse gasA gas that contributes to the natural greenhouse effect. The primary six greenhouse gases (GHGs) produced by human activities are: carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride. For the purpose of this report, GHG considers only CO2 and CH4.

HydrocarbonAn organic chemical compound of hydrogen and carbon (see petroleum).

Hydrocarbon productionQuantity of hydrocarbon gas and/or liquids produced.

IPIECAThe global oil and gas industry association for environmental and social issues.

MudCommon term for drilling fluid

Nitrogen Oxides (NOX)Nitrogen Oxides represent the sum of nitric oxide (NO) and nitrogen dioxide (NO2) expressed as NO2 equivalent. Nitrous oxide (N2O) is not included as a component of NOX. NOX emissions occur from the combustion of fossil fuels for industry and transport and are a function of the type and quantity of fuel burned and the type of combustion device in which they are burned.

Appendix B – Glossary

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Non-Aqueous Drilling Fluid (NADF)A drilling fluid in which the continuous phase is a water-immiscible fluid such as an oleaginous material (eg, mineral oil, enhanced mineral oil, paraffinic oil, or synthetic material such as olefins and vegetable esters). NADFs serve many purposes under difficult drilling conditions. NADFs are usually reused.

NMVOCNon Methane Volatile Organic Compounds: all hydrocarbons other than methane that can vaporise at normal temperature and pressure.

NormalisationTo compare emissions from different regions or sources it is useful to relate them to the size of the activity causing the emission. For example, tonnes of CO2 can be presented by their ratio to tonnes of oil and gas produced. This procedure is called normalisation.

OffshoreFor this report ‘offshore’ refers to operations that take place at sea, including inland seas directly connecting to oceans. Operations in bays, in major inland seas, e.g. the Caspian Sea, or in other inland seas directly connected to oceans are counted as offshore.

OnshoreFor this report ‘onshore’ refers to operations that take place within a landmass, including swamps, lakes, rivers and estuaries, but excluding major inland seas.

On-site combustionThe local combustion of fuels by E&P companies to produce energy for their operations.

OperatorTerm used to describe a company appointed by venture stakeholders to take primary responsibility for day-to-day operations for a specific plant or activity.

ProcessingThe separation of oil, gas, and natural gas liquids and the removal of impurities.

Produced water (PW)The water (generally brine) brought up from the hydrocarbon-bearing strata during the extraction of oil and gas, including formation water, injection water, and any chemicals added downhole or during the oil/water separation process. For the purposes of this report produced water discharges from crude oil and natural gas facilities are categorised by the source of production and not the location where they occur, in other words, where production is offshore and discharges are generated from an onshore facility, the discharges are reported as offshore.

ProductionAll production activities including production drilling, process and treatment, flaring and venting, pipeline transport, and terminal operations. (see hydrocarbon production)

Purchased energyEnergy purchased in the form of electricity or steam.

SO2Sulphur dioxide.

Source of emissionsIn the case of gaseous emissions, this refers to the process by which the emissions are released. Source categories are energy, flare, vent, fugitive losses and unspecified.

SpillAny loss of containment that reaches the environment (i.e. not inclusive of any released volume retained within secondary or other confinement), irrespective of the quantity recovered (i.e. it represents the gross volume reaching the environment, not a net volume remaining in the environment). Spills occurring from support and standby vessels are included but spills of produced water or process waste water are excluded. Includes loss of containment resulting from acts of sabotage (such as theft of oil from pipelines and storage); excludes loss as a result of ‘acts of terrorism’/attacks on infrastructure.

SyntheticsSynthetic material as applied to synthetic-based drilling fluid means material produced by the reaction of specific purified chemical feedstock, as opposed to the traditional base fluids such as diesel and mineral oil which are derived from crude oil solely through physical separation processes.

Synthetic-based drilling fluidA drilling fluid that has a synthetic material as its continuous phase with water as the dispersed phase. Synthetic-based drilling fluids are a subset of non-aqueous drilling fluids.

TonneA metric tonne; equivalent to 1 000 kilogrammes or 2 205 pounds.

TransportThe transfer of hydrocarbons from the site of production to the point of commercial metering or terminal or offshore loading device.

Upstream industryThose operations within the industry to the point where the produced resource is metered into the transportation system. This includes exploration & production.

VentingThe controlled release of unburned gas to the atmosphere.

Water-based drilling fluid (mud)A drilling fluid in which water or a water miscible fluid is the continuous phase and the suspending medium for solids, whether or not oil is present.

For further information and publications, please visit our website at

www.ogp.org.uk

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OGP DATA SERIES - اصلی

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