Environmental performance indicators - 2013 data

REPORT

2013eDECEMBER2014

DATA SERIES

Environmental performance indicators 2013 data

Disclaimer

Whilst every effort has been made to ensure the accuracy of the information contained in this publication, neither IOGP 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 recipients 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.

Copyright notice

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DATA SERIES

Environmental performance indicators 2013 data

Revision history

VERSION DATE AMENDMENTS

1.0 December 2014 First release

REPORT

2013eDECEMBER2014

4Environmental performance indicators - 2013 data

Acknowledgements

Environment Committee

Environmental Data Subcommittee

5

Contents

Executive summary 7Gaseous emissions 8Energy consumption 9Flaring 9Aqueous discharges 9Non-aqueous drilling fluids retained on cuttings discharged to sea 10Spills 10

Introduction 11

Scope of data submissions 121. Gaseous emissions 17

Detailed review 171.1 Carbon dioxide (CO2) 201.2 Methane (CH4) 221.3 Greenhouse Gas (GHG) 241.4 Non-Methane Volatile Organic Compounds (NMVOCs) 261.5 Sulphur dioxide (SO2) 281.6 Nitrogen oxides (NOX) 30

2. Energy consumption 323. Flaring 344. Produced water 36

4.1 Quality (oil content) of produced water discharges 384.2 Quantity of oil discharged in produced water per unit of production 404.3 Produced Water Injection 42

5. Non-aqueous drilling fluids retained on cuttings discharged to sea 446. Spills 47

6.1 Oil spills 476.2 Chemical spills 56

APPENDIX A: Data Tables 57Scope of data submissions 58Detailed review 59

Gaseous emissions 59Energy Consumption 62Flaring 64Produced water 65Non-Aqueous Drilling Fluids retained on cuttings discharged to sea 69Spills 70

Glossary 79


Contributing companies

The environmental statistics for 2013 were derived from data provided by the following companies:

ADNOCBashneftBGBPCairn EnergyChevronCNOOCConocoPhillipsDolphin EnergyDONG E&PDragon OilE.ONEni E&P DivisionExxonMobilGalpGDF SUEZ E&P InternationalHess CorporationHuskyINPEXKosmosKuwait Oil CompanyMaersk Oil

Marathon Oil CompanyMOLNexenOil SearchOMVPan American EnergyPerencoPetrobrasPetronasPremier OilPTT EPQatar PetroleumRepsolRWEShell CompaniesStatoilSuncorTotalTullowWintershallWoodside

7Executive summary

Executive summary

The International Association of Oil and Gas Producers (IOGP) has collected environmental data from its member companies every year since 1999. 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 industrys wish to be more transparent about its operations.

This report summarizes information on exploration and production (E&P) activities carried out by contributing IOGP member companies in 2013.

Data have been submitted for the report by 43 of IOGPs 63 member operating companies working in 84 countries worldwide. This total includes three companies reporting for the first time this year and 39 of the 43 companies that contributed data in 2012.

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 spills of oil and chemicals.

These data represent oil and gas wellhead production of 2,077 million tonnes (in the region of 15.5 billion BOE), about 29% of 2013 global production sales*. This is a 7% decrease in the production represented in this report compared with 2012. Regional coverage is uneven, ranging from 95% of known production in Europe to 10% in the Former Soviet Union (FSU).

* Source: BP Energy Review 2014


Gaseous emissionsReleases of gases to the atmosphere are an integral and inevitable part of exploration, production and processing operations.

In 2013 participating IOGP member companies reported emissions of: 259 million tonnes of carbon dioxide (CO2) equivalent to 128 tonnes of

carbon dioxide per thousand tonnes of hydrocarbon production 1.9 million tonnes of methane (CH4) equivalent to 1.0 tonne of methane

per thousand tonnes of hydrocarbon production 921 thousand tonnes of non-methane volatile organic compounds

(NMVOC) equivalent to 0.5 tonnes of NMVOC per thousand tonnes of hydrocarbon production

400 thousand tonnes of sulphur dioxide (SO2)* equivalent to 0.2 tonnes of SO2 per thousand tonnes of hydrocarbon production

801 thousand tonnes of nitrogen oxides (NOX) equivalent to 0.4 tonnes of NOX per thousand tonnes of hydrocarbon production.

Including the effects introduced by changes in the companies reporting between 2013 and 2012:

CH4 emissions per unit of production decreased in 2013 by 27% compared with 2012

SO2 emissions per unit of production increased in 2013 by 24% compared with 2012

NOX emissions per unit of production decreased in 2013 by 7% compared with 2012

CO2 emissions per unit of production decreased by 4% and NMVOC per unit of production increased by 2% in 2013 compared with 2012.

* In this report SO2 refers to the sum of sulphur dioxide (SO2) and sulphur trioxide (SO3) expressed as SO2 equivalent.

9Executive summary

Energy consumptionProduction 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 2013, IOGP reporting companies consumed on average 1.5 gigajoules of energy for every tonne of hydrocarbon produced; a 4% increase compared with the 2012 average.

As in previous years, data indicate that onshore production in 2013 was more energy intensive than offshore production.

FlaringFlaring 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 safety or technical reasons or for lack of export infrastructure, is not used or exported.

In 2013, 15.1 tonnes of gas was flared for every thousand tonnes of hydrocarbon produced versus 13.9 tonnes in 2012 and 15.7 in 2011.

Aqueous dischargesProduced water is the most significant water discharge associated with E&P Operations. For every tonne of hydrocarbon produced in 2013 (including oil, condensates and gas), 0.6 tonne of produced water was discharged and 1.1 tonne of produced water was re-injected.

The quality of produced water discharges is measured in terms of oil content. In 2013, the average concentration of oil in produced water was 10.5 mg/l for onshore discharges and 13.4 mg/l for offshore discharges. When expressed in terms of oil production, overall, these discharges are equivalent to 8.2 tonnes of oil for every million tonnes of hydrocarbon produced.

Comparison with 2012 data indicates that the average concentration of oil in produced water discharged remains essentially unchanged in 2013. The average quantity of oil discharged per unit of hydrocarbon production increased by 18%.


Non-aqueous drilling fluids retained on cuttings discharged to seaWhile 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 2013, reporting companies discharged 15,347 tonnes of non-aqueous base fluids (NABF) on drill cuttings to sea. 96% of these discharges contained Group III base fluids and 4% contained Group II fluids.

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.

SpillsFor 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 2013, participating IOGP member companies reported 2,270 oil spills greater than 1 barrel in size, resulting in a normalized spill rate of 1.2 oil spills per million tonnes of hydrocarbon production (0.8 in 2012, 1.5 in 2011).

The reported oil spills >1 barrel resulted in the release of a total of 7,585 tonnes of oil. The quantity of oil spilled per unit of hydrocarbon production has fallen to 4.1 tonnes per million tonnes production, 13% lower than the rate for 2012 and 48% lower than the rate for 2011.

* Definitions of Group I, II and III base fluids are provided in section 5.

11

The International Association of Oil and Gas Producers (IOGP) has collected environmental data from its member companies every year since 1999. The ultimate aim of this effort is to provide a representative statement on the environmental performance of the contributing IOGP 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 industrys 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 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 IOGP membership. These definitions align with the IPIECA/API/IOGP Oil and gas industry guidance on voluntary sustainability reporting, IOGP Report No. 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 2012 and summary reports for activities in 2001 and 2002 have previously been published and are available from the IOGP website at www.iogp.org/our-library.

Introduction

Introduction


Scope of data submissions

43 IOGP member companies reported environmental information for, on average, 8 countries each. Data from 84 countries are represented in the report.

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

This report only reflects the performance of the IOGP member companies that have provided data. The data represent 2,077 million tonnes of hydrocarbon production, approximately equivalent to 29% of 2013 world production as reported in the BP Statistical Review 2014. There is substantial variation in regional coverage as shown in Figures 1 and 2.

In Europe, where a high percentage (95%) of hydrocarbon production is represented, the information can be taken to approximate industry performance in that region.

In Africa (62%), Asia/Australasia (33%) and South & Central America (34%), the data give a broad indication of industry performance.

For the Middle East (23%) and North America (20%), the regional coverage is less comprehensive, giving a weaker indication of industry performance.

For the Former Soviet Union (FSU), the largest oil producing region in the world, data reported by participating companies represent just 10% of the total sales production for that region and thus may not be representative of the regions performance, see Figure 3.

Figure 1: Percentage of total production in this database

South & Central America 8%

North America 14%

Middle East 19%

FSU 5% Europe 17%

Asia/Australasia 14%

Africa 23%

13

NORTH AMERICA

AFRICA

MIDDLE EAST

ASIA/ AUSTRALASIA

SOUTH & CENTRALAMERICA

EUROPE

FORMER SOVIET UNION (FSU)

North America S&C AmericaEuropeAfrica FSU Middle EastAsia/Australasia

DATA SETS

13 162520 14 1620

3320%DATA SETS

7795%DATA SETS

7262% DATA SETS

1810% DATA SETS

3023%DATA SETS

6333% DATA SETS

3734%

Legend

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 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 directly comparable, but the percentage of world production figures are given as indicative of the relative regional contributions in the database. %

nDATA SETS

Country represented/Not representedNote: Regional allocations for some countries differ from those used in the IOGP Articles of Association

n

Figure 2: Data provided for the 7 geographic regions

NORTH AMERICA

SOUTH & CENTRAL AMERICA

EUROPE

AFRICA

MIDDLE EAST

ASIA/AUSTRALASIA

FORMER SOVIET UNION(FSU)



Note: IOGP 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.

Figure 3: Production associated with IOGP database and 2013 production in BP Statistical Review of World Energy by region

Changes in results between years may not necessarily reflect actual changes in performance.

The number of companies reporting has fluctuated between years, as shown in Table 1.

Not all metrics are reported consistently by all companies, as shown in Table 2. Performance indicator results may be influenced by 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.

0

500

1000

1500

2000 Total 2013 knownproduction as published in BP Statistical Review2014 (106t)

Production in this report as percentage of total known production for region

South & Central America

North America

Middle East

FSUEuropeAsia/Australasia

Africa

mill

ion

tonn

es h

ydro

carb

on p

rodu

ctio

n

62%33%

95%

10%

23%20%

34%

15

Year

2009 2010 2011 2012 2013

Companies Reporting 35 36 41 43 43

Companies Joining (did not report previous year)

3 2 5 3 4

Companies Leaving (reported previous year)

0 1 0 1 4

Note: This represents the number of companies reporting hydrocarbon production. Some companies that reported hydrocarbon production did not report e.g. atmospheric emission or produced water discharge data for all countries consistently each year.

Table 1: Company participation

Data are presented on a normalized basis to help control for these effects. Normalized analyses are only possible when data are available for both the metric to be normalized (emissions, discharges, spills) and the normalizer (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 normalized produced water discharge results in the Middle East region where around 18% of reported production is included.



Region

Africa Asia/ Australasia Europe FSUMiddle East

North America


All regions

Gas

emis

sion

s

CO2 100 99 83 100 100 100 100 97 CH4 100 85 83 96 100 100 100 95 NMVOC 96 84 82 96 87 100 94 91 SO2 96 98 82 100 93 99 94 94 NOX 98 98 83 100 93 100 95 94

Energy consumed

98 98 98 100 100 100 98 99

Flaring 100 98 100 96 100 99 98 99Oil discharged in produced water

79 93 89 72 18 71 95 70

Oil spills 98 94 78 96 74 91 100 88

Green: (90%100%): data fairly representative of participating companies in the region Yellow: (65%89%) data moderately representative Orange: (30%64%): lower confidence that data are representative Red: (0%29%): lowest confidence that data are representative

Table 2: Percentage of reported production included in normalized analyses 2013

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 recognized 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 each year. 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.

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 changes are listed at the end of Appendix A.

17Detailed review - gaseous emissions

Detailed review

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

CO2: carbon dioxide released to the atmosphere from any source CH4: methane released to the atmosphere, from any source GHG: greenhouse 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: the sum of sulphur dioxide (SO2) and sulphur trioxide (SO3) expressed as

SO2 equivalent 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.

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.

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 normalized emission ratios is complex.

These factors include: presence or absence of infrastructure for gas sales gasoil ratio reservoir and field characteristics use of hydrocarbon recovery techniques regulatory and contractual aspects location and logistics age of the fields emissions controls.

*See for example: Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions (2003) Joint IPIECA/API/IOGP report (in revision); Compendium of Greenhouse Gas Emission Estimation Methodologies for the Oil and Gas Industry, API, 2009; SangeaTM Energy and Emissions Estimating System, API, http://GHG.API.org


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

Normalized figures for 20072013 emissions are shown in Figures 4 and 5: 128 tonnes of carbon dioxide (CO2) per thousand tonnes of hydrocarbon

production 1.0 tonne 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 0.4 tonne of nitrogen oxides (NOX) per thousand tonnes of hydrocarbon

production.

In 2013, participating IOGP member companies reported emissions of: 259 million tonnes of CO2 1.9 million tonnes of CH4 921 thousand tonnes of NMVOC 400 thousand tonnes of SO2 801 thousand tonnes of NOX.

Emis

sion

s - t

onne

s pe

r tho

usan

d to

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62%33%

95%

10%

23%20%

34%0.0

0.3

0.6

0.9

1.2

1.5 2013

2012

2011

2010

2009

2008

2007

NOXSO2NMVOCCH4

0.97

0.49

0.21

0.40

Figure 4: Atmospheric emissions per thousand tonnes hydrocarbon production


Emis

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s - t

onne

s pe

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62%33%

95%

10%

23%20%

34%0

50

100

150

200 CH4 expressed as CO2 Equivalent (CH4 21)

CO2

2013201220112010200920082007

20

128

Figure 5: CO2 and CH4 expressed as CO2 equivalent per thousand tonnes hydrocarbon production

The following sub-sections present the overall emission data for the years 2007 to 2013, regional emission data for 2009 to 2013 and atmospheric emissions categorized by the source of the gas release for 2013.

The reporting options for the allocation of source categories are Energy, Flare, Vents, Fugitive losses and Other/Unspecified (see Glossary).


Figure 6: CO2 emissions per unit of hydrocarbon production (20072013)

Regional averages for the quantity of carbon dioxide emissions per unit of production vary from 43 to 205 tonnes of carbon dioxide per thousand tonnes of hydrocarbon production, as shown in Figure 7.

In 2012 the range was between 58 and 217 tonnes per thousand tonnes of production. The wide range across regions points towards the strong influence of different types of production assets on greenhouse gas metrics.

Tonn

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O 2 p

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pro

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62%33%

95%

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34%0

20

40

60

80

100

120

140

160

2013201220112010200920082007

128133132133135

142142

1.1 Carbon dioxide (CO2)Emissions of carbon dioxide occur principally from the combustion of fuels for energy production and from flaring. 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 production

Global CO2 emissions normalized to hydrocarbon production for 2013 participating companies were 128 tonnes of CO2 per thousand tonnes of production, a 4% reduction compared with that for the 2012 participating companies, as shown in Figure 6.


Tonn

es C

O 2 p

er th

ousa

nd to

nnes

pro

duct

ion

62%33%

95%

10%

23%20%

34%0

50

100

150

200

250


North America

Middle East


Africa

67

204

Overall 128

43

8194

162

2052013

2012

2011

2013 overall(128)

1.1.2 Emissions by source

The source was specified for 57% of the carbon dioxide emissions reported for 2013.

As shown in Figure 8, 61% of the reported carbon dioxide emissions where the source was specified were from energy use, 35% were from flaring and 4% were from venting.

Vents 4% Fugitive losses 0.01%

Flare 35%

Energy 61%

Figure 7: CO2 emissions per unit of hydrocarbon production (by region)

Figure 8: CO2 emissions by source 2013

Note: based only on emissions where the source is specified.


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.). In addition, some methane emissions result from incomplete combustion of hydrocarbons in flares.


Participating companies in 2013 reported normalized emissions of 0.97 tonnes of CH4 per thousand tonnes of hydrocarbon production. This is 27% lower than the average result for the 2012 participating companies as indicated in Figure 9.

This increase is principally due to changes in the companies reporting CH4 data in 2013. When companies that did not report CH4 data consistently for the years 2011, 2012 and 2013 are excluded from the calculation, the CH4 emissions are 1.09, 1.02 and 1.07 tonnes per thousand tonnes of hydrocarbon production respectively.

Tonn

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H4 p

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pro

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62%33%

95%

10%

23%20%

34%0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

2013201220112010200920082007

0.97

1.331.24

1.181.14

1.021.04

Figure 9: CH4 emissions per unit of hydrocarbon production (20072013)

Regional averages for methane emissions expressed per unit of production vary from 0.1 to 2.6 tonnes of methane per thousand tonnes of hydrocarbon production, as shown in Figure 10. In 2012, the range was between 0.2 and 2.7 tonnes per thousand tonnes of production. The wide range across regions points towards the strong influence of different types of production assets on greenhouse gas metrics.

The aforementioned change in companies reporting in 2013 significantly affected the results for the Asia/Australasia region, resulting in a drop of average intensity for the region of 58%.


Tonn

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H4 p

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62%33%

95%

10%

23%20%

34%0.0

0.5

1.0

1.5

2.0

2.5

3.0


North America

Middle East


Africa

0.90

2.56

Overall 0.97

0.12

0.450.57

1.131.04

2013

2012

2011

2013 overall(0.97)

Figure 10: CH4 emissions per unit of hydrocarbon production (by region)


The source was specified for 49% of the total methane emissions reported in 2013.

Where the source was specified, 42% were from vents (including venting, vessel loading, tank storage, etc.), 27% of methane emissions were from fugitive losses, 26% were from flaring and 5% were from energy use, as shown in Figure 11.

Vents 42%

Fugitive losses 27%

Flare 26%

Energy 5%

Figure 11: CH4 emissions by source 2013



1.3 Greenhouse Gas (GHG) For E&P activities, CO2 and CH4 are the principal contributors to greenhouse gas emissions.

The CO2 and CH4 data presented above are used to calculate an estimate of the GHG emissions for the contributing IOGP reporting companies, using the conversion to CO2 equivalent (GHG = CO2 + 21 CH4).


Participating companies in 2013 reported normalized emissions of 148 tonnes of GHG per thousand tonnes of hydrocarbon production. This represents an 8% reduction in intensity compared with the average for 2012 participating companies (see Figure 12).

Tonn

es G

HG

per t

hous

and

tonn

es p

rodu

ctio

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62%33%

95%

10%

23%20%

34%0

20

40

60

80

100

120

140

160

180

2013201220112010200920082007

148161158158159163

164

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

Figure 12: GHG emissions per unit of hydrocarbon production (20072013)

Regional averages for quantity of greenhouse gas emissions per unit of production vary from 46 to 258 tonnes of greenhouse gas per thousand tonnes of hydrocarbon production, as shown in Figure 13. In 2012, the range was between 61 and 271 tonnes per thousand tonnes of production. The wide range across regions points towards the strong influence of different types of production assets on greenhouse gas metrics.


Tonn

es G

HG

per t

hous

and

tonn

es p

rodu

ctio

n

62%33%

95%

10%

23%20%

34%0

50

100

150

200

250

300


North America

Middle East


Africa

86

258

Overall 148

46

91106

192

227 2013

2012

2011

2013 overall(148)

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

Figure 13: GHG emissions per unit of hydrocarbon production (by region)

1.3.2 Emissions by source The source was specified for 56% of the total reported greenhouse gas emissions.

Where the source is specified, 55% of the reported greenhouse gas emissions are from energy use, 34% are from flaring, 6% are from venting or vents and 5% are attributable to fugitive losses, as shown in Figure 14.

Vents 8%

Fugitive losses 3%

Flare 34% Energy 55%

Figure 14: GHG emissions by source 2013



1.4 Non-Methane Volatile Organic Compounds (NMVOCs)NMVOC emissions mainly occur from non-combustion sources such as flaring, venting and fugitive releases (including crude oil loading). In addition, to a lesser extent NMVOCs are emitted in the exhaust of combustion equipment.


Global normalized NMVOC emissions for 2013 participating companies were 0.49 tonnes per thousand tonnes of hydrocarbon, essentially unchanged compared with the average for 2012 participating companies. See Figure 15.

Tonn

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MVO

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62%33%

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0.1

0.2

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0.4

0.5

0.6

0.7

0.8

2013201220112010200920082007

0.490.480.490.500.53

0.58

0.68

Figure 15: NMVOC emissions per unit of hydrocarbon production (20072013)

Regional averages for quantity of NMVOC emitted per unit of production vary from 0.23 to 0.83 tonnes per thousand tonnes of hydrocarbon production, as shown in Figure 16.

In 2012, the range was between 0.22 and 0.71 tonnes per thousand tonnes of production.


Tonn

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MVO

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34%0.0

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0.7

0.8

0.9


North America

Middle East


Africa

0.76

0.83

Overall 0.49

0.260.230.25

0.43

0.62

2013

2012

2011

2013 overall(0.49)

Figure 16: NMVOC emissions per unit of hydrocarbon production (by region)


The source was specified for 51% of the total NMVOC emissions reported in 2013.

Where the source is specified, 35% of NMVOC emissions reported for 2013 come from venting or vents, 30% from flaring, 26% from fugitive losses and 9% from energy use, as shown in Figure 17.

Vents 35%

Fugitive losses 26%

Flare 30%

Energy 9%

Figure 17: NMVOC emissions by source 2013



1.5 Sulphur dioxide (SO2)Sulphur oxide emissions by the E&P industry arise through oxidation during combustion of sulphur naturally contained within fuels or flared gas (H2S content) and diesel (sulphur content).


Global SO2 emissions for 2013 participating companies were 0.21 tonnes per thousand tonnes of hydrocarbon production, a 24% increase compared with the average for 2012 participating companies. See Figure 18.

This increase is principally due to changes in the companies reporting SO2 data. When companies that did not report SO2 data consistently for the years 2011, 2012 and 2013 are excluded from the calculation, the SO2 emissions are 0.18, 0.17 and 0.18 tonnes per thousand tonnes of hydrocarbon production respectively.

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34%0.00

0.05

0.10

0.15

0.20

0.25

2013201220112010200920082007

0.21

0.170.170.170.180.180.18

Figure 18: SO2 emissions per unit of hydrocarbon production (20072013)

Regional averages for quantity of SO2 emissions expressed per unit of production vary from 0.02 to 0.57 tonne per thousand tonnes of hydrocarbon production, as shown in Figure 19.

In 2011, the range was between 0.03 and 0.64 tonne per thousand tonnes of production. The wide range across regions points towards the strong influence of different types of production assets on the metric.


Tonn

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North America

Middle East


Africa

0.180.17Overall 0.21

0.57

0.24

0.050.02

0.09

2013

2012

2011

2013 overall(0.21)

Figure 19: SO2 emissions per unit of hydrocarbon production (by region)


The source was reported for 55% of the total SO2 emissions in 2013.

Where the source was specified, 72% of sulphur dioxide emissions reported in 2013 were from flaring, 25% were from energy use and 3% were from venting or vents, as shown in Figure 20.

Vents 3%

Flare 72%

Energy 25%

Figure 20: SO2 emissions by source 2013



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 equipment, loading and technology.


Global NOX emissions for 2013 participating companies were 0.40 tonnes per thousand tonnes of production, 7% lower than the average for 2012 participating companies. See Figure 21.

Tonn

es N

O x p

er th

ousa

nd to

nnes

pro

duct

ion

62%33%

95%

10%

23%20%

34%0.0

0.1

0.2

0.3

0.4

0.5

2013201220112010200920082007

0.400.43

0.410.400.390.410.41

Figure 21: NOX emissions per unit of hydrocarbon (20072013)

In 2013, normalized NOX emissions ranged from 0.10 to 0.80 tonne per thousand tonnes of hydrocarbon production for participating companies, as shown in Figure22.

In 2012, the range was between 0.13 and 0.83 tonne per thousand tonnes of production. The wide range across regions points towards the strong influence of different types of production assets on the metric. The large change in results between 2012 and 2013 for South & Central America is due to the change in companies participating between years.


Tonn

es N

O x p

er th

ousa

nd to

nnes

pro

duct

ion

62%33%

95%

10%20%

34%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

0.29

0.80

Overall 0.40

0.10

0.18

0.35

0480.47

2013

2012

2011

2013 overall(0.40)

Figure 22: NOX emissions per unit of hydrocarbon (by region)


The source was reported for 48% of the total nitrogen oxide emissions reported in 2013.

Where the source was specified, 93% of nitrogen oxide emissions reported in 2013 were from energy use. The remaining 7% were from flaring, as shown in Figure 23.

Vents 0.01%Flare 7%

Energy 93%

Figure 23: NOX emissions by source 2013



2. Energy consumptionThe energy used to produce oil and gas covers a range of activities. These include:

powering compressors to re-inject produced gas or to export it through pipelines

driving turbines to generate electricity needed for operational activities, including logistics, and for living quarters (e.g. at offshore platforms)

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.

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 2013, IOGP reporting companies consumed on average 1.5 gigajoules of energy for every tonne of hydrocarbon produced, as shown in Figure 24. This is an increase of 4% compared with the 2012 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 2013 was more energy intensive than offshore production.

Giga

joul

es e

nerg

y pe

r ton

ne p

rodu

ctio

n

62%33%

95%

10%

23%20%

34%0.0

0.3

0.6

0.9

1.2

1.5

1.8

2013201220112010200920082007

Unspecified

Purchased energy

Onsite combustion

Figure 24: Energy consumed per unit of hydrocarbon production by source (20072013)

33Detailed review - energy consumption

Source unspecified 16 %

Source specified 84%

Onsite combustionPurchased energy

91%

9%

Giga

joul

es e

nerg

y p

er to

nne

prod

uctio

n

62%33%

95%

10%20%

34%0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0


North America

Middle East


Africa

1.34

3.09

Overall 1.46

0.34

1.06

1.28

1.91

1.44

2013

2012

2011

2013 overall(1.46)

Figure 26: Energy consumed per unit of hydrocarbon production by region

Figure 25: Energy consumed by source (20072013)

In Figure 26, the (overall) energy consumption is normalized against the quantity of hydrocarbons produced for each region.This analysis shows that operations in North America were the most energy intensive (3.09 gigajoules per tonne of hydrocarbon produced), while the Middle East was the least energy intensive (0.34 gigajoules per tonne). The wide range across regions points towards the strong influence of different types of production assets on the metric.

The majority of energy requirements were met by combustion of fuels on-site rather than by purchase of electricity or steam, see Figure 25.


3. 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 safety or technical reasons or for lack of export infrastructure, is not used or exported.

In 2013, 15.1 tonnes of gas were flared for every thousand tonnes of hydrocarbon produced versus 13.9 in 2012 and 15.7 in 2011, as shown in Figure 27.

Tonn

es h

ydro

carb

on fl

ared

pe

r tho

usan

d to

nnes

pro

duct

ion

62%33%

95%

10%

23%20%

34%0

5

10

15

20

25

2013201220112010200920082007

15.113.9

15.716.017.6

18.820.4

Figure 27: Hydrocarbon flared per unit of hydrocarbon production (20072013)

35Detailed review - flaring

Tonn

es h

ydro

carb

on fl

ared

pe

r tho

usan

d to

nnes

pro

duct

ion

62%33%

95%

10%20%

34%0

10

20

30

40

50

60


North America

Middle East


Africa

9.757.09

Overall 15.12

5.37

20.61

3.83

16.08

43.912013

2012

2011

2013 overall(15.12)

Figure 28: Hydrocarbon flared per unit of hydrocarbon production (by region)

Figure 28 shows flaring per unit of hydrocarbon production, as reported by the participating companies, by region.


4. Produced waterProduced water is the highest volume liquid discharge generated during the production of oil and gas. It consists of formation water (water present naturally in the reservoir), floodwater (water 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 2013 was approximately 1.6 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 categorized 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. Note 3: There are marked differences in the scope of reporting for each region between the years, onshore and offshore.

37Detailed review - produced water

Aqueous discharge covers the discharge of produced water, mainly produced formation water.

In 2013, participating companies reported the oil content of 841 million tonnes of discharged produced water. Where the location was specified, approximately 91% of water discharged was from offshore operations and 9% was from onshore operations.

For every tonne of hydrocarbon produced in 2013, 0.6 tonne of produced water was discharged to the surface and 1.0 tonne of produced water was re-injected. In 2012, 0.5 tonne of produced water was discharged to the surface and 0.9 tonne was re-injected.

The overall average oil content of produced water discharges was 13.1 mg/l, compared with 13.3 mg/l in 2012 and 11.9 mg/l in 2011. Offshore the average oil content in produced water was 13.4 mg/l, whilst onshore it was 10.5 mg/l (See Figures 29, 30 and 31).

Overall 8.2 tonnes of oil was discharged per million tonnes of hydrocarbon production in 2013 by participating companies, an 18% increase compared with 2012 participating companies (7.0 in 2012 and 6.3 in 2011). The quantity of oil discharged per unit of hydrocarbon production was 1.9 t/106 t onshore and 10.0 t/106 t offshore (See Figures 32, 33 and 34).


4.1 Quality (oil content) of produced water discharges

Mill

igra

mm

es o

il pe

r litr

e of

pro

duce

d w

ater

dis

char

ged

62%33%

95%

10%

23%20%

34%0

5

10

15

20

OverallOffshoreOnshore

2013

2012

2011

2010

2009

2008

2007

10.53

13.38 13.13

Figure 29: Oil discharged per unit of produced water discharged

The global quantity of oil discharged per unit of produced water was 13.1 mg/l for 2013 participating companies, essentially unchanged compared with the average for 2012 participating companies.

Onshore results show a 50% increase compared with 2012. This increase is largely due to a change in the companies reporting offshore data. Offshore the average has decreased by 3% compared with 2012.

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 36 and 37 for produced water re-injection).

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


Mill

igra

mm

es o

il pe

r litr

e of

pro

duce

d w

ater

di

scha

rged

(equ

ivale

nt to

tonn

es p

er m

illio

n to

nnes

)

33%20%

34%0

5

10

15

20

25

30


North America

Middle East


Africa

14.16

Overall 10.5

no d

ata

1.20

8.15

20.70

2013

2012

2011

2013 overall(10.5)80.08 57.59

Mill

igra

mm

es o

il pe

r litr

e of

pro

duce

d w

ater

di

scha

rged

(equ

ivale

nt to

tonn

es p

er m

illio

n to

nnes

)

33%20%

34%0

5

10

15

20

25

30


North America

Middle East


Africa

16.51

13.24

4.99

Overall 13.412.1011.94

16.48

2013

2012

2011

2013 overall(13.4)51.16 36.88

Figure 30: Oil content of produced water discharged onshore (by region)

Figure 31: Oil content of produced water discharged offshore (by region)


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

Tonn

es o

il di

scha

rged

per

mill

ion

tonn

es p

rodu

ctio

n

62%33%

95%

10%

23%20%

34%0

3

6

9

12

15


2013

2012

2011

2010

2009

2008

2007

2.53

11.27

8.18

Figure 32: Oil discharged per unit of hydrocarbon production

Overall the rate of oil discharged per unit of production for participating companies in 2013 was 18% higher compared with the average for 2012 participating companies. This is largely driven by a change in the companies reporting in the South America region between 2012 and 2013.

Regional averages for the quantity of oil discharged by unit of production of hydrocarbons vary, onshore (see Figure 33), from a few kg per million tonnes in the FSU and Middle East regions to 8.0 t/106 t in Africa and Asia/Australasia, while offshore (Figure 34) they vary from almost zero in the FSU to 20.0 t/106 t 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.


Tonn

es p

er m

illiio

n to

nnes

of p

rodu

ctio

n

33%20%

34%0

5

10

15

20


North America

Middle East


Africa

0.910.12

1.06

Overall 2.5

0.04

8.018.02

2013

2012

2011

2013 overall(2.5)

Tonn

es o

il pe

r mill

ion

tonn

es o

f pro

duct

ion

33%20%

34%0

5

10

15

20


North America

Middle East


Africa

12.86

10.57

0.620.09

Overall 11.3

9.13

19.97

9.54

2013

2012

2011

2013 overall(11.3)

Figure 33: Oil discharged per unit of hydrocarbon production onshore (by region)

Figure 34: Oil discharged per unit of hydrocarbon production offshore (by region)


4.3 Produced Water Injection

62%33%

95%

10%

23%20%

34%0%

20%

40%

60%

80%

100%


2013

2012

2011

2010

2009

2008

2007

Figure 35: Percent of produced water re-injected overallExpressed as percent of total produced water generated.

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

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

Onshore, where disposal to surface is often constrained by regulatory and environmental concerns, injection of produced water is the principal disposal route with 88% of water being returned below ground (see Figure 36).

Offshore (Figure 37), 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 2013). Exceptions to this include locations where injection would be beneficial to the management of the reservoir and water chemistry allows for reinjection 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 less than 2% of produced water was re-injected.


33%

0%

20%

40%

60%

80%

100%

OverallSouth & Central America

North America

Middle East


Africa

2013

2012

2011

0%

20%

40%

60%

80%

100%

OverallSouth & Central America

North America

Middle East


Africa

2013

2012

2011

Figure 36: Percent of produced water re-injected onshore (by region)Expressed as percent of total produced water generated onshore.

Figure 37: Percent of produced water re-injected offshore (by region)Expressed as percent of total produced water generated offshore.


5. Non-aqueous drilling fluids retained on cuttings discharged to seaWhile 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.

IOGP reports non-aqueous base fluids (NABFs) according to the classifications in Table 1.

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)

45Detailed review - non-aqueous drilling fluids

In the past, diesel-based and mineral oil-based fluids (Group I fluids) were used to address these technical challenges, but it was recognized that the discharge of cuttings with adhering diesel or oil-based muds might cause adverse environmental impacts.

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.

Figure 38 provides a regional view of adhered base fluid quantities on cuttings discharged to the sea while drilling with NADFs. Information on NABF discharges in 2013 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 2013, cuttings with Group III fluids (14,663 tonnes, 96% 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 (684 tonnes).

Absolute values rather than normalized values are shown in Figure 38. Drilling discharges are not normalized 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.


Note: NABF discharges were reported by 21 of the 43 participating companies in 2013. No Group 1 NABF discharges to the sea were reported in the years 20082013.

Figure 38: Total base fluid (NABF) retained on cuttings discharged to the sea (by region)

0 5000 10000 15000 20000 25000

2013

2012

2011

2013

2012

2011

2013

2012

2011

2013

2012

2011

2013

2012

2011

2013

2012

2011

2013

2012

2011

NABF Unspecified

NABF Group III

NABF Group II


North America

Middle East

FSU

Europe

Asia/Australasia

Africa

3040

14688

1651

23876

1135

1365

4436

1718

1210

1162

2407

2971

11528

1

4

0

0

0

153

4

2

Tonnes

47Detailed review - spills

6. SpillsSpills are an important environmental performance indicator for the oil and 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 IOGP 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. The data for these are presented in Table A.34 in Appendix A.

6.1 Oil spillsIn 2013, companies reported a total of 6,666 oil spills. Of these, 4,396 (66%) were spills of less than one barrel in volume, amounting to a total of 75 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


Figure 39: Number of oil spills >1 barrel in size, per unit of hydrocarbon production

Figure 40 shows the number of spills normalized per unit hydrocarbon production by region. Rates for 2013 vary from 0.2 to 3.8 spills per million tonnes of production.

Spill

s pe

r mill

ion

tonn

es p

rodu

ctio

n

62%33%

95%

10%

23%20%

34%0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0


2013

2012

2011

2010

2009

2008

2007

2.33

0.15

1.23

Spill

s pe

r mill

ion

tonn

es o

f pro

duct

ion

33%20%

34%0

2

4

6

8

10


North America

Middle East


Africa

0.40

2.51

0.26

3.76

Overall 1.23

0.500.25

1.79

2013

2012

2011

2013 overall(1.23)

Figure 40: Number of oil spills >1 barrel in size, per unit of hydrocarbon production (by region)


Tonn

es p

er m

illio

n to

nnes

pro

duct

ion

62%33%

10%20%

34%0

4

8

12

16

20


2013

2012

2011

2010

2009

2008

20078.42

0.31

4.13

46.98

Tonn

es p

er m

illio

n to

nnes

of p

rodu

ctio

n

33%20%

34%0

5

10

15

20

25


North America

Middle East


Africa

1.67

6.63

1.92

5.18Overall 4.13

0.670.45

10.14

2013

2012

2011

2013 overall(4.13)

Figure 41: Quantity of oil spilled, per unit of hydrocarbon production

The quantity of oil spilled per unit of hydrocarbon production in 2013, based on reports received, has fallen to 4.1 tonnes per million tonnes of production, 13% lower than the rate for 2012 as shown in Figure 41.

Figure 42: Quantity of oil spilled (oil spills >1 barrel in size), per unit of hydrocarbon production (by region)


Figures 41 and 42 show the reported quantities of oil spilled per unit of hydrocarbon production, onshore and offshore respectively, in the different geographic regions.

Tonn

es p

er m

illiio

n to

nnes

of p

rodu

ctio

n

33%20%

34%0

5

10

15

20


North America

Middle East


Africa

6.61

2.10

9.21Overall 8.4

3.60

8.46

1.39

2013

2012

2011

2013 overall(8.4)

32.5

55.5

3

49.6

3

31.7

Tonn

es p

er m

illio

n to

nnes

of p

rodu

ctio

n

33%20%

34%0

4

8

12

16

20


North America

Middle East


Africa

0.050.150.810.03

Overall 0.30.410.130.48

2013

2012

2011

2013 overall(0.3)

22.1

Figure 43: Quantity of oil spilled (oil spills >1 barrel in size), per unit of hydrocarbon production onshore (by region)

Figure 44: Quantity of oil spilled (oil spills >1 barrel in size), per unit of hydrocarbon production offshore (by region)


0

200

400

600

800

1000

1200

1400

Unspecified size>100 barrels10


Num

ber o

f spi

lls

0

200

400

600

800

1000

1200

1400

UnspecifiedOffshoreOnshore

Unspecified size

>100 barrels

10


6.1.1 Spills greater than 100 barrels in size

In 2013, 100 spills in which more than 100 barrels of oil was released (77 onshore, 7 offshore, 16 unspecified location) were reported by participating companies amounting to 4,734 tonnes. Participating companies provided incident descriptions for 78 of the 100 individual incidents.

The 4 largest of the 78 were: 367 tonnes (~2,738 barrels) of crude oil was spilled in a single sabotage/theft

incident in Nigeria 306 tonnes (~2,281 barrels) of crude oil was spilled in a single incident in

Nigeria. This incident was categorized as other: operational but no detailed information was available

280 tonnes (~2,087 barrels) of crude was spilled in a sabotage incident in Nigeria 231 tonnes (~1,723 barrels) of crude oil flowed into an emergency pit as a

result of a failure to the power supply to a treatment plant control system. 168 tonnes of the oil was recovered

Cause (excluding intentional third party damage)

A specific cause was provided for 77 of the spills >100 barrels in size in 2013.

Excluding the 32 categorized as third party damage, the remaining 45 spills >100 barrels in size were collectively associated with 24% of the total oil spilled (1,833 tonnes). Figure 48 shows the distribution of cause for operational spill incidents >100 barrels in size, where the cause was reported, for 2013.

Of the 8 spill incidents categorized as other in 2013, 1 was due to an unplanned third party electrical failure, 1 was due to interference by livestock, 2 were the result of freezing conditions and 4 were operational but no details were available.


Other 18%

Operator or technicalerror 29%

Equipment failure (excluding corrosion)

33%

Corrosion 20%

Figure 48: Operational spills >100 barrels in size, by cause excluding third party damage (2013)

As % of spill incidents >100 barrels where cause was indicated

Intentional third party damage (sabotage, theft, vandalism, etc)

Incidents caused by third party damage account for 32 of the spills >100 barrels in size where the cause was reported in 2013. These third party spills represent 2,076 tonnes of oil, 27% of the total oil spilled.


Figure 49: Operational spills 10100 barrels in size, by cause excluding third party damage (2013)

As % of spill incidents 10100 barrels where cause was indicated.

6.1.2 Spills between 10 and 100 barrels in size

Detailed information has been reported for spills between 10 and 100 barrels in size since 2010.

In 2013, 525 spills in this category were reported in total (404 onshore, 28 offshore, 93 unspecified location).

The quantity of oil recovered was reported for 82% of the 10100 barrel spills. 424 (66%) of the 640 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 176 spills between 10 and 100 barrels in size in 2013, excluding those categorized as third party damage. Collectively these operational spills for which cause was provided represent 718 tonnes of oil spilled (599 tonnes of crude oil, 60 tonnes of condensate, 26 tonnes of processed oil and 33 tonnes of unspecified oil).

Figure 49 shows the distribution of cause for operational spill incidents between 10 and 100 barrels in size, where the cause was reported, for 2013.

Other 3%Operator or technical error 27%

Equipment failure (excluding corrosion) 38%

Corrosion 32%

Intentional third party damage (sabotage, theft, vandalism, etc)

Incidents caused by third party damage account for 9 (5%) of the spills 10-100 barrels in size where the cause was reported in 2013. These spills caused by third parties represent 28 tonnes of oil


6.2 Chemical spillsIn the E&P sector chemical spills with release to the external environment occur infrequently and quantities released are generally small.

In 2013, participating companies reported 849 chemical spills greater than 1 barrel in size, totalling 4,495 tonnes. Data for these are presented in Table A.34 in Appendix A.

57Appendix A

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

Results that differ from those published in the Environmental Performance Indicators report for 2012 data (2012e) as a result of changes to historical data by the submitting companies are noted at the end of this Appendix.

APPENDIX A: Data Tables



Region Production in this report (106 t)BP Review

production (106 tProduction as % of BP

Review production

2013 Africa 373 603 62%

Asia/Australasia 271 832 33%

Europe 362 380 95%

FSU 141 1388 10%

Middle East 431 1841 23%

North America 318 1599 20%


181 533 34%

TOTAL 2077 7174 29%

2012 Africa 505 644 78%


Europe 381 399 96%

FSU 113 1370 8%




187 538 35%

TOTAL 2233 7080 32%

2011 Africa 387 600 64%


Europe 452 406 111%

FSU 127 1366 9%




194 531 37%

TOTAL 2221 6950 32%

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.

Table A.1: Production associated with IOGP database and 2013 production in BP Statistical Review of World Energy by region (Figures 2 and 3)

59Appendix A

Detailed review Gaseous emissions

2013 2012 2011

Emission per 103 t production

t/103 t

Hydrocarbon production 106 t


t/103 t



t/103 t


CO2 127.53 2011 132.80 1904 132.27 2177

CH4 0.97 1968 1.33 1762 1.24 2127

NMVOC 0.49 1882 0.48 1694 0.49 2050

SO2 0.21 1945 0.17 1772 0.17 2097

NOX 0.40 1963 0.43 1809 0.41 2100

GHG* 147.94 160.68 158.23

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

Table A.2: Emissions per unit of hydrocarbon production (Figures 4, 5, 6, 9, 12, 15, 18 and 21)

Africa Asia/ Australasia Europe FSUMiddle

EastNorth

AmericaSouth & Central

AmericaOVERALL

2013 CO2 (106 t) 77.3 45.3 28.9 11.7 18.5 65.1 12.2 259.03

CH4 (103 t) 391.6 260.8 178.7 61.5 54.0 814.3 162.7 1923.59

NMVOC (103 t) 223.6 98.3 75.4 32.5 96.9 263.0 129.2 918.83

SO2 (103 t) 31.6 5.9 14.0 34.1 229.3 55.0 30.1 399.88

NOX (103 t) 179.6 132.8 108.5 28.1 41.7 259.3 50.7 800.65

GHG* (106 t) 85.5 50.8 32.6 13.0 19.7 82.2 15.6 299.43

2012 CO2 (106 t) 78.84 49.48 31.58 11.53 13.41 62.65 7.13 254.62

CH4 (103 t) 481.92 745.47 197.22 69.25 37.12 747.17 62.87 2341.02

NMVOC (103 t) 268.62 101.81 90.17 24.60 73.18 220.47 38.44 817.30

SO2 (103 t) 27.85 13.10 12.29 31.77 147.27 60.46 11.41 304.14

NOX (103 t) 165.80 145.06 125.02 26.44 31.62 259.83 41.89 795.67

GHG* (106 t) 88.96 65.13 35.72 12.98 14.19 78.34 8.45 303.78

2011 CO2 (106 t) 79.72 64.69 34.01 12.95 17.74 53.32 26.56 288.98

CH4 (103 t) 565.24 861.66 185.89 72.54 58.36 648.87 237.74 2630.30

NMVOC (103 t) 305.25 196.72 98.03 22.68 87.71 180.38 120.36 1011.13

SO2 (103 t) 31.59 9.49 16.30 30.49 199.20 57.04 20.35 364.46

NOX (103 t) 151.00 130.94 127.01 32.58 55.59 228.63 138.45 864.20

GHG* (106 t) 91.59 82.78 37.91 14.47 18.97 66.95 31.55 344.22

Table A.3: Gross emissions of gases per region


Africa Asia/ Australasia

Europe FSU Middle East

North America

South & Central

America

OVERALL

2013 CO2 emissions (t/103 t) 205.40 167.97 93.59 81.14 43.00 203.91 66.84 127.53

Production (106 t) 372 268 301 141 430 318 181 2011

CH4 emissions (t/103 t) 1.04 1.13 0.57 0.45 0.12 2.56 0.90 0.97

Production (106 t) 372 230 301 136 430 318 181 1968

NMVOC emissions (t/103 t) 0.62 0.43 0.25 0.23 0.26 0.83 0.76 0.49

Production (106 t) 358 227 296 136 377 318 171 1882

SO2 emissions (t/103 t) 0.09 0.02 0.05 0.24 0.57 0.17 0.18 0.21

Production (106 t) 358 265 296 141 400 315 171 1945

NOX emissions (t/103 t) 0.47 0.48 0.35 0.18 0.10 0.80 0.29 0.40

Production (106 t) 366 265 300 141 400 318 172 1963

*GHG emissions (t/103 t) 227.33 191.76 105.62 90.61 45.62 257.64 85.68 147.94

2012 CO2 emissions (t/103 t) 158.00 151.56 82.63 102.13 57.87 216.65 92.91 132.80

Production (106 t) 498 319 380 113 230 289 76 1904

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

Production (106 t) 398 278 379 113 230 289 76 1762


Production (106 t) 386 238 376 113 206 311 65 1694

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

Production (106 t) 394 279 380 113 229 311 66 1772

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

Production (106 t) 394 316 380 113 230 311 66 1809

*GHG emissions (t/103 t) 183.40 207.90 93.57 115.02 61.25 270.93 110.28 160.68

2011 CO2 emissions (t/103 t) 205.78 183.53 74.95 99.95 47.48 180.57 136.11 132.27

Production (106 t) 387 351 452 127 371 295 194 2177

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

Production (106 t) 387 307 451 123 371 295 194 2127


Production (106 t) 372 274 448 122 347 295 193 2050

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

Production (106 t) 382 277 452 126 371 295 194 2097

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

Production (106 t) 382 280 452 126 371 295 194 2100

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

NB: Data only included where gas quantity and production level are both reported.*GHG: Total Greenhouse Gases (CO2 + CH4 expressed in CO2 equivalent: GHG = CO2 + 21 CH4).

Table A.4: Emissions per unit of production (Figures 7, 10, 13, 16, 19 and 22)

61Appendix A

CO2 (106 t) CH4 (103 t) NMVOC (103 t) SO2 (103 t) NOX (103 t) GHG* (106 t)

2013 Energy 90.19 47.65 40.71 55.84 357.43 91.19

Flare 51.69 246.41 144.46 159.34 26.20 56.86

Fugitive losses 0.02 250.96 121.42 0.00 0.00 5.29

Vents 5.40 399.72 167.15 6.03 0.05 13.80

Other/Unspecified E&P 111.73 978.86 445.09 178.67 416.97 132.29

OVERALL 259.03 1923.59 918.83 399.88 800.65 299.43

2012 Energy 91.08 45.46 16.74 46.53 342.10 92.04

Flare 48.62 197.28 123.93 91.96 21.97 52.76

Fugitive losses 0.03 271.89 65.64 0.00 0.00 5.74

Vents 8.94 322.02 184.79 5.79 0.19 15.70


OVERALL 254.62 2341.02 817.30 304.14 795.67 303.78

2011 Energy 92.07 192.44 15.84 50.54 388.14 96.11

Flare 57.07 384.45 138.42 115.59 29.94 65.15

Fugitive losses 0.03 384.90 76.02 4.70 0.00 8.11

Vents 8.09 462.56 197.36 12.28 0.16 17.81


OVERALL 288.98 2630.30 1011.13 364.46 864.20 344.22

Table A.5: Emissions by source (Figures 8, 11, 14, 17, 20 and 23)

CO2 CH4 NMVOC SO2 NOX GHG*

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

2013

Emissions (t/103 t)

143.02 108.50 1.36 0.55 0.59 0.41 0.39 0.08 0.39 0.36 171.88 119.63

Production (106 t)

782 1081 782 1038 724 1011 747 1050 752 1063 782 1081

2012

Emissions (t/103 t)

118.56 134.26 1.49 0.77 0.60 0.45 0.30 0.12 0.53 0.37 144.95 149.83

Production (106 t)

668 977 564 939 544 923 574 972 577 972 668 977

2011

Emissions (t/103 t)

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 (106 t)

745 1230 740 1185 709 1139 739 1156 742 1156 745 1230

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 CH4).

Table A.6: Gas emissions in production activities per unit of hydrocarbon production onshore and offshore


Energy Consumption

2013 2012 2011 2010 2009

% onsite combustion 77 76 81 80 80

% purchased 8 5 5 5 5

% unspecified 16 19 16 16 16

Total Energy Consumption (GJ/t) 1.46 1.40 1.54 1.47 1.48

Production (106 t) 2053 2047 2024 2092 2151

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

Table A.7: Energy consumed per unit of hydrocarbon production (Figure 24)

Onsite Purchased Unspecified TOTAL

2013 Africa 409.11 21.16 94.93 525.20

Asia/Australasia 310.79 9.22 191.76 511.76

Europe 402.08 47.76 6.84 456.68

FSU 94.19 12.34 46.66 153.19

Middle East 91.43 29.30 26.53 147.27

North America 780.15 90.15 114.20 984.50

South & Central America 227.21 6.76 10.81 244.78

TOTAL 2314.96 216.69 491.73 3023.38

2012 Africa 382.05 19.74 91.68 493.47


Europe 422.01 39.21 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


TOTAL 2203.43 152.72 523.77 2879.90

2011 Africa 355.47 16.24 88.52 460.24


Europe 468.11 30.51 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


TOTAL 2511.11 133.33 476.65 3121.08

Table A.8: Gross energy consumption (million gigajoule) by region (Figure 25)

63Appendix A

% Onsite Combustion

% Purchased % Unspecified Total Energy Consumption*

(GJ/t)

Productiona (106 t)

2013 Africa 77.8 4.0 18.2 1.44 364

Asia/Australasia 60.5 1.8 37.7 1.91 267

Europe 88.1 10.4 1.5 1.28 356

FSU 60.3 8.3 31.4 1.06 141

Middle East 62.0 19.9 18.1 0.34 430

North America 79.2 9.2 11.6 3.09 318

South & Central America 92.6 2.8 4.5 1.34 178

TOTAL 76.4 7.2 16.4 1.46 2053

2012 Africa 77.4 4.0 18.6 1.01 490


Europe 90.1 8.3 1.6 1.24 376

FSU 67.5 0.6 32.0 1.16 113

Middle East 42.4 29.9 27.7 0.24 383

North America 83.1 5.6 11.3 3.39 292


TOTAL 76.5 5.3 18.3 1.40 2047

2011 Africa 77.2 3.5 19.3 1.19 387


Europe 92.4 6.0 1.6 1.14 444

FSU 67.3 0.7 32.1 1.11 123

Middle East 84.6 6.6 8.8 0.78 233

North America 81.1 6.0 12.9 3.06 294


TOTAL 80.4 4.3 15.3 1.54 2024

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

Table A.9: Energy consumption per unit of hydrocarbon production (gigajoules per tonne ) by region (Figure 26)

2013 2012 2011

Onshore (GJ/t) 1.87 1.60 2.24

Offshore (GJ/t) 1.19 1.21 1.23

Unspecified (GJ/t) 1.34 1.47 1.30

Overall (GJ/t) 1.46 1.40 1.54

Table A.10: Energy consumption per unit of hydrocarbon production (gigajoules per tonne) onshore and offshore


Flaring

2013 2012 2011 2010 2009 2008 2007

Total flared (t/106 t) 15.12 13.93 15.73 16.02 17.59 18.75 20.44

Production (106 t) 2058 2071 2176 2235 2327 2080 2041

Table A.11: Hydrocarbon flared per unit of production (tonnes per thousand tonnes) (Figure 27)



North America

South & Central

America

OVERALL

2013 Total flared (t/103 t) 43.91 16.08 3.83 20.61 5.37 7.09 9.75 15.12

Production (106 t) 373 267 360 136 430 315 177 2058

2012 Total flared (t/103 t) 35.29 15.98 3.46 10.52 5.13 5.56 5.36 13.93

Production (106 t) 498 284 378 113 416 308 73 2071

2011 Total flared (t/103 t) 50.73 17.56 3.64 11.69 6.43 3.42 11.29 15.73

Production (106 t) 382 345 443 121 410 283 193 2176

Table A.12: Flaring per unit of hydrocarbon production (tonnes per thousand tonnes) by region (Figure 28)

65Appendix A

Produced water

2013 2012 2011 2010 2009 2008 2007

Onshore 10.53 7.02 8.12 14.24 11.60 12.80 17.49

Offshore 13.38 13.86 12.22 12.85 13.64 14.84 15.48

Unspecified 14.21 15.82 14.56 14.60 12.98 21.64 18.84

OVERALL 13.13 13.30 11.85 13.14 13.34 14.77 15.84

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

Table A.13: Oil discharged per unit of produced water discharged (milligrammes oil per litre of produced water discharged) (Figure 29)



North America

South & Central

America

OVERALL

2013 Onshore Oil discharged (t/106 t) 20.70 8.15 1.20 0.00 no data 14.16 57.59 10.53

PW discharged (106 t) 7.21 55.88 0.18 1.14 0.00 11.60 0.66 76.67

Offshore Oil discharged (t/106 t) 16.48 11.94 12.10 51.16 4.99 13.24 16.51 13.38

PW discharged (106 t) 129.01 317.91 162.05 0.08 5.48 37.13 99.54 751.19

Unspecified Oil discharged (t/106 t) 14.21 no data no data no data no data no data no data 14.21

PW discharged (106 t) 13.16 no data no data no data no data no data no data 13.16

OVERALL Oil discharged (t/106 t) 16.49 11.37 12.09 3.28 4.98 13.46 16.78 13.13

PW discharged (106 t) 149.38 373.79 162.22 1.22 5.48 48.73 100.20 841.01

Total Produced Water (106 t)* 195 988 267 8 164 335 287 2245

2012 Onshore Oil discharged (t/106 t) 2.36 5.77 1.80 0.00 0.00 23.07 3.85 7.02

PW discharged (106 t) 7.98 58.43 4.37 0.10 0.01 8.44 0.65 79.99


PW discharged (106 t) 128.16 281.70 214.44 0.09 5.75 27.46 6.75 664.34

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

PW discharged (106 t) 24.84 18.13 0.60 no data no data 9.02 no data 52.60


PW discharged (106 t) 160.99 358.26 219.41 0.19 5.76 44.92 7.40 796.92



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


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


PW discharged (106 t) 26.18 1.20 0.21 no data no data 6.92 no data 34.51


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


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.

Table A.14: Oil content of produced water discharged (Figures 30 and 31)


2013 2012 2011 2010 2009 2008 2007

Onshore 2.53 1.94 2.41 3.16 3.02 3.62 5.65

Offshore 11.27 9.98 8.49 9.14 10.17 11.08 12.18

OVERALL 8.18 6.95 6.33 6.99 7.48 8.54 9.77

Table A.15: Oil discharged per unit of hydrocarbon production (tonnes per million tonnes) (Figure 32)



North America

South & Central

America

OVERALL


Production (106 t) 41 57 7 58 33 155 42 393


Production (106 t) 227 197 255 43 44 47 130 942

Unspecified Oil discharged (t/106 t) 6.78 no data 0.02 no data no data 1.40 no data 1.99

Production (106 t) 28 no data 59 no data no data 25 no data 112


Production (106 t) 296 253 321 101 77 226 172 1446


Production (106 t) 57 62 11 52 110 140 27 458


Production (106 t) 241 200 274 41 128 48 38 968


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


Production (106 t) 346 302 352 93 237 238 64 1633


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


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

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

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

Environmental performance indicators - 2013 data

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