data series environmental performance indicators 2014 data

REPORT

2014eNOVEMBER2015

DATA SERIES

Environmental performance indicators – 2014 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 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.

Copyright notice

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DATA SERIES

Environmental performance indicators – 2014 data

Revision history

VERSION DATE AMENDMENTS

1.0 November 2015 First release

REPORT

2014eNOVEMBER2015

4Environmental performance indicators - 2014 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 12

Detailed review 171. Gaseous emissions 17

1.1 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 2014 were derived from data provided by the following companies:

ADNOCBGBPCairn EnergyChevronCNOOCConocoPhillipsDEADolphin EnergyDONG E&PDragon OilE.ONeni E&P DivisionExxonMobilGalpHess CorporationHuskyINPEXKosmosKuwait Oil CompanyMærsk OilMarathon Oil Company

MOLOil SearchOMVOriginPan American EnergyPerencoPetrobrasPJSOC BashneftPluspetrolPremier OilPTT EPQatar PetroleumRepsolSasolShell CompaniesStatoilSuncorTotalTullow OilWintershallWoodside

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 industry’s 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 2014.

Data have been submitted for the report by 43 of IOGP’s 59 member operating companies working in 86 countries worldwide. This total includes two companies reporting for the first time this year and 40 of the 43 companies that contributed data in 2013 (1 company that contributed in 2014 and 2012 did not contribute in 2013).

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 2,116 million tonnes (15.8 billion BOE), about 29% of 2014 global production sales*, with the absolute and relative production values virtually unchanged compared with 2013. Regional coverage is uneven, ranging from 90% of known production in Europe to 12% in the Former Soviet Union (FSU).

* Source: BP Statistical Review of World Energy 2015


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

In 2014 participating IOGP member companies reported emissions of: • 286 million tonnes of carbon dioxide (CO2) – equivalent to 134 tonnes of

carbon dioxide per thousand tonnes of hydrocarbon production• 1.8 million tonnes of methane (CH4) – equivalent to 0.9 tonne of methane

per thousand tonnes of hydrocarbon production• 962 thousand tonnes of non-methane volatile organic compounds

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

• 371 thousand tonnes of sulphur dioxide (SO2)* – equivalent to 0.2 tonnes of SO2 per thousand tonnes of hydrocarbon production

• 901 thousand tonnes of nitrogen oxides (NOX) – equivalent to 0.4 tonnes of NOX per thousand tonnes of hydrocarbon production.

Changes in emissions per units of production reported between 2013 and 2014, including the effects introduced by changes in the companies reporting between the years were:

• Normalized CO2 increased by 5%• Normalized CH4 decreased by 6%• Normalized NMVOC increased by 2%• Normalized NOX increased by 10%• Normalized SO2 decreased by 10%

* 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 2014, IOGP reporting companies consumed on average 1.4 gigajoules of energy for every tonne of hydrocarbon produced; a 1% reduction compared with the 2013 average.

As in previous years, data indicate that onshore production in 2014 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 2014, 14.8 tonnes of gas was flared for every thousand tonnes of hydrocarbon produced versus 15.1 tonnes in 2013 and 13.9 tonnes per thousand tonnes in 2012.

Aqueous dischargesProduced water is the most significant water discharge associated with E&P Operations. For every tonne of hydrocarbon produced in 2014 (including oil, condensates and gas), 0.6 tonne of produced water was discharged and 1.2 tonnes of produced water was re-injected.

The quality of produced water discharges is measured in terms of oil content. In 2014, the average concentration of oil in produced water was 4.7 mg/l for onshore discharges and 12.8 mg/l for offshore discharges. When expressed in terms of oil production, overall, these discharges are equivalent to 6.9 tonnes of oil for every million tonnes of hydrocarbon produced.

Comparison with 2013 data indicates that the average concentration of oil in produced water discharged decreased by 14% in 2014. The average quantity of oil discharged per unit of hydrocarbon production decreased by 16%.


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 2014, companies that provided data on cuttings disposition discharged 16,846 tonnes of non-aqueous base fluids (NABF) on drill cuttings to sea. 95% of these discharges contained Group III base fluids and 5% 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 a loss of containment event in which material released reaches the environment, i.e. is not retained within secondary or other containment. The spill volume reported includes the total volume that reaches the environment, irrespective of the quantity of material that may be recovered.

In 2014, participating IOGP member companies reported 1,723 oil spills greater than 1 barrel in size, resulting in a normalized spill rate of 0.9 oil spills per million tonnes of hydrocarbon production (1.2 in 2013, 0.8 in 2012).

The reported oil spills >1 barrel resulted in the release of a total of 6,667 tonnes of oil. The quantity of oil spilled per unit of hydrocarbon production has fallen to 3.4 tonnes per million tonnes production, 18% lower than the rate for 2013 and 29% lower than the rate for 2012.

* 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 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• 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 2013 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

http://www.iogp.org/our-library


Scope of data submissions

For 2014, 43 IOGP member companies reported environmental information for, on average, 9 countries each. Data reported for 2014 covered operations in a total of 86 countries.

This report only reflects the performance of the IOGP member companies that have provided data in a given year. For 2014 the data represent 2,116 million tonnes of hydrocarbon production, approximately equivalent to 29% of 2014 world production as reported in the BP Statistical Review of World Energy 2015.

To show the data from a geographical perspective, 7 regions have been defined (see Figures 1 and 2). There is substantial variation in regional coverage as shown in Figure 3.

• In Europe, where a high percentage (90% in 2014) of hydrocarbon production is represented, the information can be taken to approximate ‘industry’ performance in that region.

• In Africa (64%), Asia/Australasia (32%) and South & Central America (40%), the data give a broad indication of industry performance.

• For the Middle East (23%) and North America (18%), 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 12% of the total sales production for that region and thus may not be representative of the region’s performance, see Figure 3.

Figure 1: Regional contribution to total production reported by participating companies – 2014

South & CentralAmerica 10%

North America15%

Middle East20%

FSU 8% Europe 16%

Asia/Australasia

13%

Africa 18%

13

North America S&C AmericaEuropeAfrica FSU Middle EastAsia/Australasia

DATA SETS

13 172522 13 1718

3318%DATA SETS

9690%DATA SETS

9264% DATA SETS

2112% DATA SETS

3423%DATA SETS

7232% DATA SETS

4540%

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 atmospheric emissions, aqueous discharges, energy consumption or spills.

Number of companies providing data

% of known production (based on production in BP Statistical Review of World Energy 2015)Note: Production figures given in this report relate to ‘gross production’ whereas world data extracted from the BP Statistical Review for World Energy 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

nFigure 2: Data provided for the 7 geographic regions

NORTH AMERICA

SOUTH & CENTRAL AMERICA

EUROPE

AFRICA

MIDDLE EAST

ASIA/AUSTRALASIA

FSU



Note: IOGP production figures in this report represent wellhead production, which includes oil and gas volumes consumed in operations. The BP Statistical Review of World Energy provides data on production exported for sale.

Figure 3: 2014 production reported by participatring companies relative to 2014 production in BP Statistical Review of World Energy 2015 (by region)

Changes in results for various environmental indicators 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 consistently reported each year by all companies (reporting coverage by metric for 2014 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

2000Total production in BP stastical analysis (106t)

Production in this report (106t)

South &CentralAmerica

NorthAmerica

MiddleEast

FSUEuropeAsia/Australasia

Africa

mill

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64% 32% 90%12%

23% 18% 40%

Total 2014 knownproduction as published in BP Statistical Review ofWorld Energy 2015

2014 Productionreported byparticipating companies(percentage relativeto regional knownproduction indicated)

15

Year

2010 2011 2012 2013 2014

Companies Reporting 36 41 43 43 43

Companies Joining (did not report previous year)

2 5 3 4 3

Companies Leaving (reported previous year)

1 0 1 4 3

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 (e.g. emissions, discharges, spills) and the normalizer (e.g. 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 53% of reported production is included.



Region

Africa Asia/ Australasia Europe FSU Middle

EastNorth America

South & Central America

All regions

Gas

emis

sion

s

CO2 99 98 100 82 100 100 100 98 CH4 98 85 100 79 100 100 100 96 NMVOC 94 85 99 79 89 100 84 91 SO2 94 98 99 82 93 100 84 94 NOX 96 99 100 82 93 100 94 96

Energy consumed

99 99 100 79 100 100 100 98

Flaring 100 99 100 79 100 100 100 98Oil discharged in produced water

93 93 96 72 17 83 100 76

Oil spills 97 95 84 76 93 99 94 92

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 2014

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.

A correction was made in this report to a 2013 NAF Group III figure for the South America region, bringing the 2013 total for the region to 2,769 tonnes, from the previously published figure of 11,528 tonnes.

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• gas–oil ratio• reservoir and field characteristics• production 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


Normalized figures for 2010–2014 direct emissions are shown in Figures 4 and 5. Emissions reported are those directly emitted by the facilities operated or controlled by the participating companies. Emissions from the generation of energy (electricity, steam) purchased from third parties are not reported.

In 2014, participating IOGP member companies reported emissions of:• 134 tonnes of carbon dioxide (CO2) per thousand tonnes of hydrocarbon

production• 0.9 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 2014, participating IOGP member companies reported gross emissions of:• 286 million tonnes of CO2

• 1.8 million tonnes of CH4

• 962 thousand tonnes of NMVOC• 371 thousand tonnes of SO2

• 901 thousand tonnes of NOX.

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CO2

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Figure 5: CO2 and CH4 expressed as CO2 equivalent per thousand tonnes hydrocarbon production (2010-2014)

The following sub-sections present the normalized overall emission data for the years 2010 to 2014 and normalized, regional emission data for 2012 to 2014 for each emissions constituent.

Each sub-section also presents the atmospheric emissions categorized by the source of the gas release for 2014.

The reporting options for this categorization are Energy, Flare, Vents, Fugitive losses and Other/Unspecified (see Glossary).


Figure 6: CO2 emissions per unit of hydrocarbon production (2010–2014)

Regional averages for the quantity of carbon dioxide emissions per unit of production vary from 51 to 202 tonnes of carbon dioxide per thousand tonnes of hydrocarbon production, as shown in Figure 7.

In 2013 the range was between 43 and 205 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.

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128133 134132133

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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

Overall CO2 emissions normalized to hydrocarbon production for 2014 participating companies were 134 tonnes of CO2 per thousand tonnes of production, a 5% increase compared with that for the 2013 participating companies, as shown in Figure 6.


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202

Overall 134

51

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201

2014

2013

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2014 overall

1.1.2 Emissions by source

The source was specified for 62% of the carbon dioxide emissions reported for 2014.

As shown in Figure 8, 62% of the reported carbon dioxide emissions where the source was specified were from energy use, 35% were from flaring and 3% were from venting.

Vents 3%Fugitive losses 0.01%

Flare 35%

Energy 62%

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

Figure 8: CO2 emissions by source – 2014

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.


Overall CH4 emissions normalized to hydrocarbon production for participating companies in 2014 were 0.91 tonnes of CH4 per thousand tonnes of hydrocarbon production. This is 6% lower than the average result for the 2013 participating companies as indicated in Figure 9.

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Figure 9: CH4 emissions per unit of hydrocarbon production (2010–2014)

Regional averages for methane emissions expressed per unit of production vary from 0.14 to 2.41 tonnes of methane per thousand tonnes of hydrocarbon production, as shown in Figure 10. In 2013, the range was between 0.12 and 2.56 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.

A change in companies reporting in 2012 versus 2013 significantly affected the results for the Asia/Australasia region, resulting in a drop of average intensity for the region of 58% from 2012 to 2013.


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Overall 0.9

0.1

0.50.5

0.91.1

2014

2013

2012

2014 overall

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


The source was specified for 54% of the total methane emissions reported in 2014.

Where the source was specified, 44% were from vents (including venting, vessel loading, tank storage, etc.), 25% of methane emissions were from fugitive losses, 25% were from flaring and 6% were from energy use, as shown in Figure 11.

Vents 44%

Fugitive losses 25%

Flare 25%

Energy 6%

Figure 11: CH4 emissions by source – 2014



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 2014 reported normalized emissions of 153 tonnes of GHG per thousand tonnes of hydrocarbon production. This represents a 3% increase in intensity compared with the average for 2013 participating companies (see Figure 12).

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20142013201220112010

148 153161158158

2013

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

Figure 12: GHG emissions per unit of hydrocarbon production (2010–2014)

Regional averages for quantity of greenhouse gas emissions per unit of production vary from 54 to 252 tonnes of greenhouse gas per thousand tonnes of hydrocarbon production, as shown in Figure 13. In 2013, the range was between 46 and 258 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.

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


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Overall 153

54

9696

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2014

2013

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2014 overall

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

1.3.2 Emissions by source The source was specified for 61% of the total reported greenhouse gas emissions.

Where the source is specified, 56% of the reported greenhouse gas emissions are from energy use, 34% are from flaring, 7% are from venting or vents and 3% are attributable to fugitive losses, as shown in Figure 14.

Vents 7%

Fugitive losses 3%

Flare 34%Energy 56%

Figure 14: GHG emissions by source – 2014



1.4 Non-Methane Volatile Organic Compounds (NMVOCs)NMVOC emissions mainly occur from flaring, venting and fugitive releases and, to a lesser extent, combustion equipment.


Overall normalized NMVOC emissions for 2014 participating companies were 0.50 tonnes per thousand tonnes of hydrocarbon, essentially unchanged compared with the average for 2013 participating companies. See Figure 15.

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Figure 15: NMVOC emissions per unit of hydrocarbon production (2010–2014)

Regional averages for quantity of NMVOC emitted per unit of production vary from 0.2 to 0.9 tonnes per thousand tonnes of hydrocarbon production, as shown in Figure 16.

In 2013, the range was between 0.2 and 0.8 tonnes per thousand tonnes of production.


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


The source was specified for 49% of the total NMVOC emissions reported in 2014.

Where the source is specified, 43% of NMVOC emissions reported for 2014 come from venting or vents, 29% from flaring, 24% from fugitive losses and 4% from energy use, as shown in Figure 17.

Vents 43%

Fugitivelosses 24%

Flare 29%

Energy 4%

Figure 17: NMVOC emissions by source – 2014



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).


Overall SO2 emissions for 2014 participating companies were 0.2 tonnes per thousand tonnes of hydrocarbon production, a 10% decrease compared with the average for 2013 participating companies. See Figure 18.

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Figure 18: SO2 emissions per unit of hydrocarbon production (2010–2014)

Regional averages for quantity of SO2 emissions expressed per unit of production vary from 0.02 to 0.55 tonne per thousand tonnes of hydrocarbon production, as shown in Figure 19.

In 2013, the range was between 0.02 and 0.57 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.


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ion

62%33%

95%

10%

23%20%

34%0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

0.10.1

Overall 0.2

0.6

0.3

0.00.0

0.1

2014

2013

2012

2014 overall

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


The source was reported for 56% of the total SO2 emissions in 2014.

Where the source was specified, 75% of sulphur dioxide emissions reported in 2014 were from flaring, 24% were from energy use and 1% were from venting or vents, as shown in Figure 20.

Vents 1%

Fugitive losses 0.02%

Flare 75%

Energy 24%

Figure 20: SO2 emissions by source – 2014



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.


Overall NOX emissions for 2014 participating companies were 0.4 tonnes per thousand tonnes of production, 10% higher than the average for 2013 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

20142013201220112010

0.40.40.4

0.40.42013

2012

2011

2010

2009

2008

2007

Figure 21: NOX emissions per unit of hydrocarbon (2010–2014)

In 2014, regional normalized NOX emissions ranged from 0.1 to 0.9 tonne per thousand tonnes of hydrocarbon production as shown in Figure 22.

In 2013, the range was between 0.1 and 0.8 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 variation in results for South & Central America during the years from 2012 to 2014 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

0.9'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

0.6

0.9

Overall 0.4

0.1

0.2

0.3

0.5

0.5

2014

2013

2012

2014 overall

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


The source was reported for 52% of the total nitrogen oxide emissions reported in 2014.

Where the source was specified, 95% of nitrogen oxide emissions reported in 2014 were from energy use and 5% were from flaring, as shown in Figure 23.

Vents 0.004%

Fugitive losses 0.08%

Flare 5%

Energy 95%

Figure 23: NOX emissions by source – 2014



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 2014, IOGP reporting companies consumed on average 1.4 gigajoules of energy for every tonne of hydrocarbon produced, as shown in Figure 24. This is essentially unchanged compared with the 2013 average.

As in previous years, data indicate that onshore production in 2014 was more energy intensive than offshore production.

Giga

joul

es e

nerg

y pe

r ton

ne p

rodu

ctio

n

0.0

0.3

0.6

0.9

1.2

1.5

Unspecified

Purchased

Onsite Combustion

20142013201220112010

Unspecified

Purchased energy

Onsite combustion12%

79%

8%

Figure 24: Energy consumed per unit of hydrocarbon production – by source (2010–2014)

33Detailed review - energy consumption

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

4.0'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

1.2

3.1

Overall 1.4

0.4

1.21.3

1.5

1.4

2014

2013

2012

2014 overall

Figure 25: Energy consumption per unit of hydrocarbon production (by region)

The source of energy used was specified for 88% of the energy reported by participating companies in 2014. Where specified, the majority of energy requirements were met by combustion of fuels on-site rather than by purchase of electricity or steam.In Figure 25, 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 (3.1 gigajoules per tonne of hydrocarbon produced), while the Middle East was the least energy intensive (0.4 gigajoules per tonne). The wide range across regions points towards the strong influence of different types of production assets on the metric.


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 2014, participating companies reported 30,800 thousand tonnes of gas flared. This equates to 14.8 tonnes of gas flared for every thousand tonnes of hydrocarbon produced versus 15.1 in 2013 and 13.9 in 2012, as shown in Figure 26.

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

20142013201220112010

15.1 14.813.9

15.716.0

2013

2012

2011

2010

2009

2008

2007

Figure 26: Hydrocarbon flared per unit of hydrocarbon production (2010–2014)

35Detailed review - flaring

Tonn

es h

ydro

carb

on fl

ared

pe

r tho

usan

d to

nnes

pr o

duct

ion

62%33%

95%

10%20%

34%0

10

20

30

40

50

60'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

9.28.3

Overall 14.8

7.97.9

3.5

18.1

42.0

2014

2013

2012

2014 overall

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

Figure 27 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, as the field becomes ‘mature’.

As context, the worldwide volume of produced water reported in this database in 2014 was approximately 1.7 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 the discharges are reported as “offshore” even if discharges are generated from an onshore facility. Note 2: For various reasons companies either discharge or re-inject produced water. The split between the produced water injected and discharged may change over time and this may influence the quantity and quality of oil discharged to surface. Note 3: There are marked differences in the companies providing data 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 2014, participating companies reported the oil content of 917 million tonnes of discharged produced water. Where the location was specified, approximately 92% of water discharged was from offshore operations and 8% was from onshore operations.

• For every tonne of hydrocarbon produced in 2014, an average of 0.6 tonne of produced water was discharged to the surface and 1.2 tonne of produced water was re-injected. In 2013, 0.6 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 12.3 mg/l, compared with 13.1 mg/l in 2013 and 13.3 mg/l in 2012. Offshore the average oil content in produced water was 12.8 mg/l, whilst onshore it was 9.9 mg/l (See Figures 28, 29 and 30).

• Overall 7.5 tonnes of oil was discharged per million tonnes of hydrocarbon production in 2014 by participating companies, an 8% decrease compared with 2013 participating companies (8.2 in 2013 and 7.0 in 2012). The quantity of oil discharged per unit of hydrocarbon production was 2.5 t/106 t onshore and 11.3 t/106 t offshore (See Figures 31, 32 and 33).


4.1 Quality (oil content) of produced water discharges

Mill

igra

mm

es o

il pe

r litr

e pr

oduc

ed w

ater

dis

char

ged

62%33%

95%

10%

23%20%

34%0

3

6

9

12

15'2014

'2013

2'012

'2011

'2010

OverallOffshoreOnshore

2014

2013

2012

2014

2010

9.9

12.812.3

Figure 28: Oil discharged per unit of produced water discharged (2010-2014)

The global quantity of oil discharged per unit of produced water was 12.3 mg/l for 2014 participating companies, a 6% decrease compared with the average for 2013 participating companies.

Onshore results show a 6% decrease compared with 2013. Offshore the average has decreased by 5% compared with 2013.

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

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 35 and 36 for produced water re-injection).

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


Mill

igra

mm

es o

il pe

r litr

e pr

oduc

ed w

ater

dis

char

ged

(equ

ivale

nt to

tonn

es p

er m

illio

n to

nnes

)

33%20%

34%0

5

10

15

20

25

30'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

0.8

Overall 9.9no

dat

ano

dat

a

no d

ata

0.0

0.0

0.00.1

7.4

15.0

2014

2013

2012

2014 overall57.629.9

Mill

igra

mm

es o

il pe

r litr

e pr

oduc

ed w

ater

dis

char

ged

(equ

ivale

nt to

tonn

es p

er m

illio

n to

nnes

)

33%20%

34%0

5

10

15

20

25

30'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

14.813.3

6.66.7

Overall 12.811.910.7

17.4

2014

2013

2012

2014 overall51.2 36.9

Figure 29: Oil content of produced water discharged onshore (by region)

Figure 30: 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

2

4

6

8

10

12'2014

'2013

2'012

'2011

'2010


2014

2013

2012

2014

2010

2.0

11.3

7.5

Figure 31: Oil discharged per unit of hydrocarbon production (2010-2014)

Overall the rate of oil discharged per unit of production for participating companies in 2014 decreased by 8% compared with the average for 2013 participating companies.

Regional averages for the quantity of oil discharged per unit of hydrocarbon production in 2014 vary onshore (see Figure 32) from minimum levels in the FSU, Europe, Middle East and South & Central America regions to 7.4 t/106 t in Africa and 6.4 t/106 t in Asia/Australasia, while offshore (Figure 33) they vary from almost zero in the FSU to 18.5 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 higher) while the offshore environment is generally less sensitive to produced water discharges.


Tonn

es o

il pe

r mill

iion

tonn

es p

rodu

ctio

n

33%20%

34%0

5

10

15

20'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

0.00.11.1

Overall 2.0

0.0

6.47.4

2014

2013

2012

2014 overall

Tonn

es o

il pe

r mill

ion

tonn

es p

rodu

ctio

n

33%20%

34%0

5

10

15

20'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

12.7

18.5

10.7

0.5

Overall 11.310.4

9.6

2014

2013

2012

2014 overall

Figure 32: Oil discharged per unit of hydrocarbon production onshore (by region)

Figure 33: 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%'2014

'2013

2'012

'2011

'2010


2014

2013

2012

2011

2010

90

28

68

Figure 34: Percent of produced water re-injected overall (2010-2014)Expressed as percent of total produced water generated.

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

Over the 5 years shown in Figure 34 the proportion of water re-injected by participating companies compared with water discharged has increased offshore and has remained roughly flat onshore.

Onshore, where disposal to surface is often constrained by regulatory and environmental concerns, injection of produced water is the principal disposal route. In 2014, 90% of water produced from onshore assets was returned below ground in data sets where the volumes of re-injected water were provided by reporting companies (see Figure 35).

Offshore (Figure 36), de-oiled produced water can typically be discharged to sea with limited impact, therefore there is much less re-injection (28% in 2014 for data sets with re-injection data). 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 28% offshore, there is a large variety range 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 by participating companies in 2014.


33%

20%

0%

20%

40%

60%

80%

100%'2014

'2013

'2012

OverallSouth &CentralAmerica

NorthAmerica

MiddleEast


Africa

2014

2013

2012

0%

20%

40%

60%

80%

100%'2014

'2013

'2012

OverallSouth &CentralAmerica

NorthAmerica

MiddleEast


Africa

2014

2013

2012

Figure 35: Percent of produced water re-injected onshore (by region)Expressed as percent of total produced water generated onshore.

Figure 36: 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 3.

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

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

Table 3: NABF classifications

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 directly discharged.

Figure 38 provides a regional view of adhered base fluid quantities on cuttings discharged to the sea while drilling with NADFs. Absolute values rather than normalized values are shown in Figure 38, because drilling activity is not directly linked to hydrocarbon production. The number of wells drilled in a given year is influenced by many factors 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.

Information on NABF discharges in 2014 has been provided by 22 of the 43 reporting companies.

Analysis shows, for the companies reporting NABF retained on cuttings in 2014, that most cuttings discharges included Group III fluids (15,949 tonnes, 95% of the total reported), whereas discharges of cuttings with Group II fluids were limited (5% of the total reported). No discharges of cuttings with Group I fluids were reported.


Note: NABF discharges were reported by 22 of the 43 participating companies in 2014. No Group 1 NABF discharges to the sea were reported in the years 2008–2014.

Figure 37: Total base fluid (NABF) retained on cuttings discharged to the sea (by region)

A correction was made by a reporting company to a previously published 2013 NAF Group III figure for the South America region, bringing the 2013 total for the region to 5,284 tonnes, from the previously published figure of 11,528 tonnes.

0 3,000 6,000 9,000 12,000 15,000

NABF Unspecified

NABF GROUP III

NABF GROUP II

2014

2013

2012

2014

2013

2012

2014

2013

2012

2014

2013

2012

2014

2013

2012

2014

2013

2012

2014

2013

2012

NABF Unspecified

NABF Group III

NABF Group II


North America

Middle East

FSU

Europe

Asia/Australasia

Africa

1,651

153

1,135

14,688

2,417

6,283

1

1,210

1,162

1,251

2,971

5,284

2,769

4

26

0

0

0

4,101

2

1,365

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 from which the released material reaches the environment (i.e. is not retained within secondary or other containment). The volume reported represents the total volume that reached the enviuronment, irrespective of quantity of released material that may be 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.33 in Appendix A.

6.1 Oil spillsIn 2014, companies reported a total of 6,702 oil spills. Of these, 4,979 (74%) were spills of less than one barrel in volume, amounting to a total of 100 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 2014, 1,723 spills greater than 1 barrel in size were reported, representing a total of 6,667 tonnes of oil. 89% of the reported oil spills (6,111 tonnes) occurred onshore and 8% occurred offshore (442 tonnes). The location was not specified for the remaining 3%.

Figure 38 shows the total number of spills normalized per unit of hydrocarbon production onshore and offshore. The normalized rate for 2014 was 0.9 oil spills per million tonnes of production (1.2 in 2013, 0.8 in 2012). The normalized rate of spills offshore is lower than that onshore.


Figure 38: Number of oil spills >1 barrel in size, per unit of hydrocarbon production (2010-2014)

Figure 39 shows the number of spills normalized per unit hydrocarbon production by region. Rates for 2014 vary from 0.1 to 3.1 spills per million tonnes of production.

Oil s

pills

per

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

4.0'2014

'2013

2'012

'2011

'2010


2014

2013

2012

2011

20101.9

0.1

0.9

Oil s

pills

per

mill

ion

tonn

es p

rodu

ctio

n

33%20%

34%0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

0.4

2.0

0.4

3.1

Overall 1.2

0.4

0.1

0.9

2014

2013

2012

2014 overall

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


Tonn

es o

f oil

spill

ed p

er m

illio

n to

nnes

pro

duct

ion

62%33%

10%20%

34%0

4

8

12

16'2014

'2013

2'012

'2011

'2010


2014

2013

2012

2011

20107.6

0.4

3.4

Tonn

es o

f oil

spill

ed p

er m

illio

n to

nnes

pro

duct

ion

33%20%

34%0

4

8

12

16'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

1.9

4.3

0.9

3.7Overall 3.4

1.6

0.6

9.5

2014

2013

2012

2014 overall

Figure 40: Quantity of oil spilled, per unit of hydrocarbon production (2010-2014)

The quantity of oil spilled per unit of hydrocarbon production in 2014, based on reports received, has fallen to 3.4 tonnes per million tonnes of production, 18% lower than the rate for 2013 as shown in Figure 40.

Figure 41: Quantity of oil spilled (spills >1 barrel in size), per unit of hydrocarbon production (by region)


Figures 42 and 43 show the reported quantities of oil spilled per unit of hydrocarbon production, onshore and offshore respectively, in the different geographic regions.

Tonn

es o

il sp

illed

per

mill

ion

tonn

es p

rodu

ctio

n

33%20%

34%0

4

8

12

16'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

5.9

1.3

5.5

Overall 7.6

13.9

6.7

1.8

2014

2013

2012

2014 overall

55.5

49.6

54.3

Tonn

es o

il sp

illed

per

mill

ion

tonn

es p

rodu

ctio

n

33%20%

34%0

4

8

12

16'2014

'2013

'2012


NorthAmerica

MiddleEast


Africa

0.00.00.10.1Overall 0.30.7

0.00.7

2014

2013

2012

2014 overall

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

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


0

200

400

600

800

1,000

1,200

1,400Unspecified

Offshore

Onshore

Unspecified size>100 barrels10<X<100 barrels1<X<10 barrels

Unspecified

Offshore

Onshore

Num

ber o

f oil

spill

s

Spill size

1,087

712

320

19 367

8 061 36 49

Figure 44: Distribution of oil spills onshore and offshore (2014) – number of spills in each size category

Figure 44 shows the distribution of spills larger than 1 barrel in terms of number of spills in each size category for 2014. In terms of number of events, the distribution is dominated by the number of spills between 1 and 10 barrels in size. However, as indicated in Figure 46, 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 result in 67% of the oil volume reported spilled in 2014 for spills > 1 barrel.

In addition to the data shown in Figure 44, a total of 4,979 spills (4,133 onshore, 844 offshore, and 2 unspecified location) of less than 1 barrel in size were reported by participating companies. These were not included in the analyses for the reasons stated previously.


0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500Unspecified

Offshore

Onshore

Unspecified size>100 barrels10<X<100 barrels1<X<10 barrels

Unspecified

Offshore

Onshore

Quan

tity

of o

il sp

illed

(ton

nes)

Spill size

1,344

498

33 0 95 26

4,207

2890 59 24 86

Figure 45: Distribution of oil spills onshore and offshore, by size (2014) – quantity of oil spilled (tonnes)


6.1.1 Spills greater than 100 barrels in size

In 2014, participating companies reported 75 spills in which a volume of more than 100 barrels of oil was released (67 onshore and 8 offshore), collectively amounting to 4,497 tonnes released. Participating companies provided incident descriptions for 72 of the 75 individual incidents.

The 4 largest of the 72 were:• 762 tonnes (~5,686 barrels) of crude oil was spilled in a single third party

sabotage/theft incident onshore in Nigeria• 517 tonnes (~3,858 barrels) of crude oil was spilled in another third party

sabotage/theft incident onshore in Nigeria• 312 tonnes (~2,332 barrels) of crude was spilled as a result of equipment failure

(excluding corrosion) onshore in USA. A gland nut failed on the well head casing causing the release. All of the oil spilled was recovered.

• 201 tonnes (~1,500 barrels) of crude was spilled onshore in Colombia due to corrosion on an 8” flowline.

Cause (excluding intentional third party damage)

A specific cause was provided for 71 of the spills >100 barrels in size in 2014.

Excluding the 30 categorized as third party damage, the remaining 41 spills >100 barrels in size were collectively associated with 42% (1,873 tonnes) of the total oil spilled in these larger incidents. Figure 48 shows the distribution of cause, where the cause was reported, for operational spill incidents >100 barrels in size for 2014. Equipment failure (excluding corrosion) was the leading cause reported for 2014 of larger operational spills that were not induced by third parties.


Other 2%

Operator ortechnical error31%

Equipment failure(excluding corrosion) 45%

Corrosion 22%

Figure 46: Operational spills >100 barrels in size, by cause excluding third party damage (2014)

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 30 of the spills >100 barrels in size where the cause was reported in 2014. These third party spills represent 2,552 tonnes of oil, 58% of the total oil spilled in larger spill events.


Figure 47: Operational spills 10–100 barrels in size, by cause excluding third party damage (2014)

As % of spill incidents 10–100 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 2014, 342 spills in this category were reported in total (320 onshore, 19 offshore, 3 unspecified location).

The quantity of oil recovered was reported for 79% of the 10–100 barrel spills. 1,159 (69%) of the 1,436 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 ~96% (327) of the spills reported in the 10-100 barrels size category in 2014. Of these, 258 spills were operational spills not induced by third party damage. Collectively these operational spills for which cause was provided represent 1,112 tonnes of oil spilled (949 tonnes of crude oil, 100 tonnes of condensate, 34 tonnes of processed oil and 29 tonnes of unspecified oil).

Figure 47 shows the distribution of cause for operational spill incidents between 10 and 100 barrels in size, where the cause was reported, for 2014.

Other 2%

Operator or technicalerror 19%

Equipment failure(excluding corrosion)

38%

Corrosion 41%

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

Incidents caused by third party damage account for 69 (21%) of the spills 10-100 barrels in size where the cause was reported in 2014. These spills caused by third parties represent 289 tonnes of oil, or roughly 26% of the volume reported for cause-specified events in this spill size category.


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 2014, participating companies reported 608 chemical spills greater than 1 barrel in size, totalling 1,606 tonnes. Data for these are presented in Table A.33 in Appendix A.

57Appendix A

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

APPENDIX A: Data Tables



Region Production in this report (106 t)

Production in BP Statistical Review of World Energy (106 t)

Production as % of production in BP

Statistical Review of World Energy

2014 Africa 370 575 64%

Asia/Australasia 280 875 32%

Europe 332 368 90%

FSU 170 1,369 12%

Middle East 425 1,880 23%

North America 319 1,733 18%


218 549 40%

TOTAL 2,116 7,348 29%

2013 Africa 373 603 62%


Europe 362 380 95%

FSU 141 1,388 10%




181 533 34%

TOTAL 2,077 7,174 29%

2012 Africa 505 644 78%


Europe 381 399 96%

FSU 113 1,370 8%




187 538 35%

TOTAL 2,233 7,080 32%

NB: Production figures given in this report relate to ‘gross production’ whereas world data extracted from the BP Statistical Review of World Energy 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 2014 production in BP Statistical Review of World Energy 2015 (by region) (Figures 1 and 3)

59Appendix A

Detailed review Gaseous emissions

2014 2013 2012

Emission per unit production

t/103 t

Hydrocarbon production 106 t


t/103 t



t/103 t


CO2 134.05 2076 127.53 2011 132.80 1,904

CH4 0.91 2028 0.97 1968 1.33 1,762

NMVOC 0.50 1925 0.49 1882 0.48 1,694

SO2 0.19 1990 0.21 1945 0.17 1,772

NOX 0.44 2026 0.40 1963 0.43 1,809

GHG* 153.13 147.94 160.68

*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 FSU Middle

EastNorth

AmericaSouth & Central

AmericaOVERALL

2014 CO2 (106 t) 74.52 54.84 28.69 12.30 21.76 64.44 28.97 285.51

CH4 (103 t) 400.20 222.56 164.36 63.70 59.45 770.91 165.72 1,846.89

NMVOC (103 t) 221.37 101.48 90.36 26.87 161.20 192.76 167.96 962.00

SO2 (103 t) 30.33 5.76 11.89 37.96 219.33 45.49 20.11 370.88

NOX (103 t) 171.30 145.71 107.82 29.41 43.00 275.73 128.32 901.29

GHG* (106 t) 82.92 59.51 32.14 13.64 23.01 80.63 32.45 324.29

2013 CO2 (106 t) 77.30 45.30 28.89 11.70 18.54 65.10 12.19 259.03

CH4 (103 t) 391.58 260.83 178.70 61.53 53.96 814.30 162.69 1,923.59

NMVOC (103 t) 223.58 98.27 75.42 32.49 96.86 263.01 129.21 918.83

SO2 (103 t) 31.57 5.92 14.03 34.06 229.25 54.96 30.08 399.88

NOX (103 t) 179.60 132.78 108.45 28.08 41.73 259.34 50.67 800.65

GHG* (106 t) 85.52 50.78 32.64 12.99 19.67 82.20 15.61 299.43

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 2,341.02

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

Table A.3: Gross emissions of gases per region


Africa Asia/ Australasia

Europe FSU Middle East

North America

South & Central

America

OVERALL

2014 CO2 emissions (t/103 t) 201.16 178.24 86.04 86.31 50.89 201.61 132.47 134.05

Production (106 t) 366 276 332 139 425 319 218 2076

CH4 emissions (t/103 t) 1.10 0.94 0.50 0.47 0.14 2.41 0.76 0.91

Production (106 t) 363 237 331 134 425 319 218 2,028

NMVOC emissions (t/103 t) 0.64 0.43 0.28 0.19 0.43 0.60 0.92 0.50

Production (106 t) 347 238 327 134 377 319 183 1,925

SO2 emissions (t/103 t) 0.09 0.02 0.04 0.27 0.55 0.14 0.11 0.19

Production (106 t) 347 276 328 139 397 319 183 1,990

NOX emissions (t/103 t) 0.46 0.53 0.32 0.19 0.11 0.86 0.62 0.44

Production (106 t) 356 276 332 139 398 319 205 2026

*GHG emissions (t/103 t) 224.17 197.93 96.45 96.23 53.79 252.31 148.44 153.13

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 2,011

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 1,968


Production (106 t) 358 227 296 136 377 318 171 1,882

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 1,945

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 1,963

*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 1,904

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 1,762


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

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 1,772

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 1,809

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

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)

2014 Energy 110.15 55.66 19.52 50.53 446.18 111.32

Flare 60.86 252.52 140.49 154.83 24.57 66.17

Fugitive losses 0.02 249.21 112.15 0.04 10.07 5.25

Vents 5.38 440.89 202.96 1.99 0.02 14.64

Other/Unspecified E&P 109.10 848.62 486.88 163.48 420.45 126.92

OVERALL 285.51 1846.89 962.00 370.88 901.29 324.30

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 1,923.59 918.83 399.88 800.65 299.43

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

Other/Unspecified E&P 105.95 1,504.37 426.20 159.86 431.42 137.54

OVERALL 254.62 2,341.02 817.30 304.14 795.67 303.78

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

2014

Emissions (t/103 t)

151.41 123.53 1.33 0.59 0.63 0.45 0.33 0.10 0.47 0.43 179.24 135.50

Production (106 t)

842 1,074 838 1,031 761 1,004 782 1,048 807 1,058 842 1074

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 1,081 782 1,038 724 1,011 747 1,050 752 1,063 782 1,081

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

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

2014 2013 2012 2011 2010

% onsite combustion 80 77 76 81 80

% purchased 8 8 5 5 5

% unspecified 13 16 19 16 16

Total Energy Consumption (GJ/t) 1.44 1.46 1.40 1.54 1.47

Production (106 t) 2,074 2,053 2,047 2,024 2,092

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

2014 Africa 404.30 21.69 90.78 516.76

Asia/Australasia 344.77 13.45 61.64 419.86

Europe 392.87 46.12 7.52 446.51

FSU 105.75 15.57 47.05 168.37

Middle East 104.15 49.19 26.80 180.13

North America 796.12 81.89 118.21 996.22

South & Central America 242.67 17.66 11.66 271.99

TOTAL 2,390.63 245.57 363.66 2,999.84

2013 Africa 409.11 21.16 94.93 525.20


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


TOTAL 2,314.96 216.69 491.73 3,023.38

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 2,203.43 152.72 523.77 2,879.90

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

63Appendix A

% Onsite Combustion

% Purchased % Unspecified Total Energy Consumption*

(GJ/t)

Productiona (106 t)

2014 Africa 78.0 4.2 17.7 1.40 366

Asia/Australasia 82.1 3.2 14.7 1.50 279

Europe 88.0 10.4 1.7 1.34 332

FSU 61.8 9.5 28.7 1.22 134

Middle East 57.7 27.4 14.9 0.42 425

North America 79.9 8.2 11.9 3.12 319

South & Central America 89.1 6.6 4.3 1.24 218

OVERALL 79.6 8.2 12.2 1.44 2,074

2013 Africa 77.8 4.0 18.2 1.44 364


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


OVERALL 76.4 7.2 16.4 1.46 2,053

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


OVERALL 76.5 5.3 18.3 1.40 2,047

* 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 25)

2014 2013 2012

Onshore (GJ/t) 1.72 1.87 1.60

Offshore (GJ/t) 1.23 1.19 1.21

Unspecified (GJ/t) 1.38 1.34 1.47

Overall (GJ/t) 1.44 1.46 1.40

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


Flaring

2014 2013 2012 2011 2010

Total flared (t/106 t) 14.84 15.12 13.93 15.73 16.02

Production (106 t) 2,076 2,058 2,071 2,176 2,235

Table A.11: Hydrocarbon flared per unit of production (tonnes per thousand tonnes) (Figure 26)



North America

South & Central

America

OVERALL

2014 Total flared (t/103 t) 42.04 18.09 3.48 7.87 7.86 8.32 9.17 14.84

Production (106 t) 370 278 331 134 425 319 218 2,076

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 2,058

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 2,071

Table A.12: Flaring per unit of hydrocarbon production (tonnes per thousand tonnes) (by region) (Figure 27)

65Appendix A

Produced water

2014 2013 2012 2011 2010

Onshore 9.85 10.53 7.02 8.12 14.24

Offshore 12.75 13.38 13.86 12.22 12.85

Unspecified 3.56 14.21 15.82 14.56 14.60

OVERALL 12.30 13.13 13.30 11.85 13.14

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 28)



North America

South & Central

America

OVERALL

2014 Onshore Oil discharged (t/106 t) 14.98 7.43 0.05 N/A N/A 29.89 0.76 9.85

PW discharged (106 t) 6.69 57.88 1.48 0.00 0.00 7.27 2.78 76.11

Offshore Oil discharged (t/106 t) 17.38 10.66 11.88 6.74 6.58 13.26 14.81 12.75

PW discharged (106 t) 127.38 325.23 195.50 0.30 3.21 39.87 128.08 819.56

Unspecified Oil discharged (t/106 t) 3.78 no data 0.00 no data no data no data no data 3.56

PW discharged (106 t) 20.13 no data 1.22 no data no data no data no data 21.34

OVERALL Oil discharged (t/106 t) 15.50 10.17 11.72 6.73 6.58 15.82 14.51 12.30

PW discharged (106 t) 154.20 383.11 198.20 0.30 3.21 47.14 130.85 917.01

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


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


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

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

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

Table A.14: Oil content of produced water discharged (Figures 29 and 30)


2014 2013 2012 2011 2010

Onshore 2.03 2.53 1.94 2.41 3.16

Offshore 11.27 11.27 9.98 8.49 9.14

OVERALL 7.51 8.18 6.95 6.33 6.99

Table A.15: Oil discharged per unit of hydrocarbon production (tonnes per million tonnes) (Figure 31)



North America

South & Central

America

OVERALL


Production (106 t) 46 68 11 80 29 190 65 489


Production (106 t) 238 194 247 42 46 49 152 968

Unspecified Oil discharged (t/106 t) 1.27 no data 0.01 no data no data 2.00 no data 0.88

Production (106 t) 60 0 60 no data no data 26 no data 146


Production (106 t) 344 262 318 123 74 266 217 1,604


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 1,446


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


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

Unspecified Oil discharged (t/106 t) 3.80 11.42 0.02 no data no data 3.08 no data 3.86

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


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

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

Table A.16: Oil discharged per unit of hydrocarbon production (by region) (Figures 32 and 33)

67Appendix A

2014 2013 2012 2011 2010

Onshore 90 88 89 90 90

Offshore 28 27 28 23 22

Unspecified 46 55 33 42 42

OVERALL 68 64 65 65 65

Total produced water generated: produced water discharged + produced water re-injected.

Table A.17: Percent of produced water re-injected overall (Expressed as percent total produced water generated) (Figure 34)


Europe FSU Middle East North America

South & Central

America

OVERALL

2014 Onshore 100 90 98 77 72 98 100 90

Offshore 26 19 26 95 95 2 0 28

Unspecified 46 no data 53 no data no data no data no data 46

OVERALL 35 64 40 86 76 90 98 68

2013 Onshore 93 91 50 61 72 97 100 88

Offshore 24 19 32 98 91 1 16 27

Unspecified 54 no data 61 no data no data no data no data 55

OVERALL 35 64 36 76 76 89 65 64

2012 Onshore 92 90 92 97 74 97 99 89

Offshore 18 15 30 97 90 2 71 28

Unspecified 28 80 71 no data no data 1 no data 33

OVERALL 26 66 42 97 77 89 90 65

Total produced water generated: produced water discharged + produced water re-injected.

Table A.18: Percent of produced water re-injected (expressed as percent total produced water generated) (by region) (Figures 35 and 36)




North America

South & Central

America

OVERALL

2014 Onshore Produced water (t/t) 0.45 7.85 6.08 0.06 0.77 2.39 4.65 2.18

Production (106t) 15.67 70.29 12.06 80.84 285.58 155.15 49.71 669.30

Offshore Produced water (t/t) 0.18 0.53 0.31 0.13 0.48 0.01 0.00 0.31

Production (106 t) 148.71 133.00 214.28 42.41 126.66 39.70 40.45 745.20

Unspecified Produced water (t/t) 0.29 0.00 0.33 no data no data no data no data 0.29

Production (106 t) 59.83 0.05 14.24 no data no data no data no data 74.12

OVERALL Produced water (t/t) 0.23 3.06 0.60 0.08 0.68 1.91 2.56 1.15

Production (106 t) 224.21 203.34 240.58 123.25 412.24 194.85 90.16 1,488.62


Production (106t) 16.73 65.60 15.70 69.71 294.74 157.64 44.36 664.47


Production (106 t) 143.77 131.07 208.88 42.83 131.37 33.67 124.27 815.86

Unspecified Produced water (t/t) 0.34 no data 0.38 no data no data no data no data 0.34

Production (106 t) 48.63 no data 13.01 no data no data no data no data 61.64


Production (106 t) 209.13 196.66 237.59 112.54 426.11 191.31 168.63 1,541.98


Production (106 t) 117.11 67.80 16.14 53.28 288.03 160.56 38.09 741.01


Production (106 t) 163.50 118.47 213.01 40.63 127.57 33.29 28.86 725.32

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

Production (106 t) 74.95 8.01 15.81 10.11 no data 3.62 no data 112.49


Production (106 t) 355.56 194.27 244.96 104.02 415.60 197.46 66.96 1,578.82

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

Table A.19: Produced water re-injected per unit of hydrocarbon production (by region)

2014 2013 2012

Total oil discharged per unit production

(t/106t)



(t/106t)



(t/106t)


Onshore 13 476 15 393 12 458

Offshore 12 934 12 915 12 853

Unspecified 2 97 8 28 13 207

OVERALL 12 1,507 13 1,336 12 1,518

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.

Table A.20: Total oil discharged (discharges + spills) per unit of hydrocarbon production

69Appendix A

Non-Aqueous Drilling Fluids retained on cuttings discharged to sea


Europe FSU Middle East North America

South & Central

America

TOTAL

2014 Group I 0 0 0 0 0 0 0 0

Group II 896 0 2 0 0 0 0 898

Group III 1,521 4,101 6,281 26 0 1,251 2,769 15,949

Unspecified 0 0 0 0 0 0 0 0

TOTAL 2,417 4,101 6,283 26 0 1,251 2,769 16,846

2013 Group I 0 0 0 0 0 0 0 0

Group II 684 0 0 0 0 0 0 684

Group III 451 153 1,365 4 0 1,162 5,284 8,419

Unspecified 0 0 0 0 0 0 0 0

TOTAL 1,135 153 1,365 4 0 1,162 5,284 9,103

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 18,217

Unspecified 470 0 0 1 0 0 1,058 1,529

TOTAL 1,651 14,688 2 1 0 1,210 2,971 20,523

NB: A correction was made by a reporting company to a previously published 2013 NAF Group III figure for the South America region, bringing the 2013 total for the region to 5,284 tonnes, from the previously published figure of 11,528 tonnes.

Table A.21: Total base fluid (NABF) retained on cuttings discharged to sea (tonnes) (by region) (Figure 37)


Spills

2014 2013 2012 2011 2010

Onshore Number of spills per 106 t 1.90 2.33 1.34 3.65 3.10

Quantity spilt (t/106 t) 7.62 8.42 8.62 11.97 7.16

Production (106 t) 801 754 735 694 798

Offshore Number of spills per 106 t 0.13 0.15 0.19 0.19 0.13


Production (106 t) 1,039 955 977 1,114 1,174

Unspecified Number of spills per 106 t 0.50 2.85 1.91 1.39 1.99


Production (106 t) 108 124 265 199 166

OVERALL Number of spills per 106 t 0.88 1.23 0.85 1.51 1.38


Production (106 t) 1,948 1,832 1,977 2,006 2,139

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

Table A.22: Number of oil spills >1 barrel in size and quantity spilled per unit of hydrocarbon production (Figure 38 and 40)



North America

South & Central

America

OVERALL

2014 Number of spills per 106 t 0.90 0.14 0.37 3.06 0.36 2.02 0.36 0.88

Quantity spilt (t/106 t) 9.46 0.56 1.59 3.69 0.94 4.33 1.88 3.38

Production (106 t) 359 266 280 129 395 315 205 1,948



Production (106 t) 367 256 282 136 320 291 181 1,832



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

Excludes spills <1 barrel in size.

Table A.23: Number of oil spills >1 barrel in size and quantity spilled per unit of hydrocarbon production (by region) (Figures 39 and 41)

71Appendix A



North America

South & Central

America

OVERALL

2014 Onshore Number of spills per 106 t 4.21 0.27 3.33 5.60 0.42 2.58 1.01 1.90


Production (106 t) 58 78 19 70 267 243 65 801

Offshore Number of spills per 106 t 0.14 0.09 0.15 0.02 0.23 0.11 0.06 0.13


Production (106 t) 241 188 250 48 127 45 140 1039

Unspecified Number of spills per 106 t 0.77 0.00 0.26 0.00 no data 0.19 no data 0.50

Quantity spilt (t/106 t) 1.38 0.00 0.31 0.00 no data 1.02 no data 1.04

Production (106 t) 60 0 11 11 no data 26 no data 108

OVERALL Number of spills per 106 t 0.90 0.14 0.37 3.06 0.36 2.02 0.36 0.88


Production (106 t) 359 266 280 129 395 315 205 1,948



Production (106 t) 54 66 22 83 276 208 45 754



Production (106 t) 250 190 247 43 44 45 136 955

Unspecified Number of spills per 106 t 5.54 no data 0.23 0 no data 0 no data 2.85

Quantity spilt (t/106 t) 14.61 no data 0.58 0 no data 0 no data 7.52

Production (106 t) 63 no data 13 10 no data 38 no data 124



Production (106 t) 367 256 282 136 320 291 181 1,832



Production (106 t) 65 74 16 53 266 209 53 735



Production (106 t) 248 182 283 41 42 47 134 977

Unspecified Number of spills per 106 t 3.73 0.11 0.08 0.11 no data 3.83 no data 1.91

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

Production (106 t) 80 44 71 19 no data 51 no data 265



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

NB: Data only included for production level where oil quantities spilled and production are reported. If no spill count (including zeros) is provided, the data are excluded from the analysis. This analysis could yield inflated values of spill intensity as some reporters may not report zeros for datasets where no spill occurred. Excludes spills <1 barrel in size.

Table A.24: Number of oil spills >1 barrel in size and quantity spilled per unit of hydrocarbon production (by region) (Figures 42 and 43)




North America

South & Central

America

OVERALL

2014 Onshore Average size (t) 12.7 6.3 4.2 1.2 3.1 2.1 5.9 4.0

Quantity spilt (t) 3,152 146 264 472 363 1,334 381 6,111

Offshore Average size (t) 5.9 1.7 4.7 6.5 0.5 0.2 0.6 3.3

Quantity spilt (t) 201 30 179 13 13 1 5 443

Unspecified Average size (t) 1.8 no data 1.2 no data no data 5.3 no data 2.1

Quantity spilt (t) 83 0 3 0 0 27 0 113


Quantity spilt (t) 2,677 92 80 702 580 1,920 296 6,347


Quantity spilt (t) 124 30 101 1 36 11 6 309

Unspecified Average size (t) 2.6 no data 2.5 no data no data no data no data 2.6

Quantity spilt (t) 921 no data 8 0 no data 0 no data 929


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

NB: Excludes spills <1 barrel in size.

Table A.25: Quantity of oil spilled per spill onshore and offshore (tonnes) (by region)

73Appendix A

<1 barrel 1<X<10 barrels

10<X<100 barrels

>100 barrels

Unspecified OVERALL*

2014 Onshore Number 4,133 1,087 320 67 61 1,535

Quantity (t) 90 498 1,344 4,207 59 6,111

Offshore Number 844 71 19 8 36 134

Quantity (t) 9 33 95 289 24 442

Unspecified Number 2 2 3 0 49 54

Quantity (t) 0 0 26 0 86 112

TOTAL Number 4,979 1,160 342 75 146 1,723

Quantity (t) 100 533 1,467 4,497 170 6,667

2013 Onshore Number 3,176 1,265 404 77 11 1,757

Quantity (t) 60 588 1,640 4,095 22 6,347

Offshore Number 725 102 28 7 24 161

Quantity (t) 10 46 97 145 19 308


Quantity (t) 4 129 306 493 0 928

TOTAL Number 4,396 1,610 525 100 35 2,270

Quantity (t) 75 765 2,044 4,734 42 7,585

2012 Onshore Number 3,157 681 205 69 37 992

Quantity (t) 50 292 869 5,222 18 6,401

Offshore Number 2,688 140 32 10 0 182

Quantity (t) 31 54 102 1,007 0 1,163


Quantity (t) 7 194 628 1,098 0 1,920

TOTAL Number 6,146 1,161 376 106 37 1,680

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

* Overall excludes spills <1 barrel in size.

Table A.26: Distribution of oil spills onshore and offshore by size (Figures 44 and 45)


<1 barrel 1<X<10 barrels

10<X<100 barrels

>100 barrels

Unspecified OVERALL*

2014 Africa Number 315 125 91 43 69 328

Quantity (t) 8.7 65.7 367.7 2,882.2 120.3 3,435.8

Asia/Australasia

Number 265 32 5 4 0 41

Quantity (t) 5.5 12.3 33.1 130.3 0.0 175.7

Europe Number 2,356 78 9 6 11 104

Quantity (t) 26.2 28.3 33.5 370.8 13.5 446.2

FSU Number 517 308 83 1 2 394

Quantity (t) 29.8 152.2 302.7 16.9 13.1 484.8

Middle East Number 67 62 28 4 52 146

Quantity (t) 1.3 36.8 103.7 235.4 0.0 375.9

North America

Number 1,112 502 111 12 12 637

Quantity (t) 16.6 214.1 557.3 567.4 23.6 1,362.3


Number 347 53 15 5 0 73

Quantity (t) 11.6 23.3 68.6 293.7 0.0 385.6

2013 Africa Number 787 407 197 52 8 664

Quantity (t) 10.6 216.5 793.3 2,705.7 6.4 3,721.8

Asia/Australasia

Number 252 59 7 2 0 68

Quantity (t) 4.0 25.4 44.8 52.2 0.0 122.5

Europe Number 2,024 110 18 4 10 142

Quantity (t) 22.9 42.7 63.1 73.7 9.5 188.9

FSU Number 601 398 104 6 2 510

Quantity (t) 20.5 199.5 339.4 163.5 1.2 703.5


Quantity (t) 1.1 28.2 85.1 502.5 0.0 615.7

North America

Number 360 523 165 29 13 730

Quantity (t) 5.8 231.3 668.8 1,005.6 24.6 1,930.3


Number 315 57 14 1 0 72

Quantity (t) 9.7 20.9 50.0 230.9 0.0 301.8

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 3,797 152 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


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


Number 624 63 16 3 0 82

Quantity (t) 12.8 28.8 55.7 76.5 0.0 161.0

* Overall excludes spills <1 barrel in size.

Table A.27: Distribution of oil spills by size (by region)

75Appendix A

Number of spills Quantity spilled to environment (tonnes)

Quantity recovered (if reported) (tonnes)*

Corrosion 9 681 453

Equipment failure (excluding corrosion) 19 834 468

Operator or technical error 12 338 146

Third party damage (sabotage, theft, vandalism, etc.) 30 2,552 429

Other 1 20 0

Total 71 4,424 1,496

NB: Quantity of oil recovered is not reported for all spills.

Table A.28: Oil spills > 100 barrels in size (where cause was indicated) – by cause – 2014 (Figure 46)


Quantity recovered (tonnes)

Corrosion 106 413 324

Equipment failure (excluding corrosion) 99 428 226

Operator or technical error 49 239 129

Third party damage (sabotage, theft, vandalism, etc.) 69 289 66

Other 4 32 31

Total 327 1,401 776


Table A.29: Oil spills 10–100 barrels (where cause was indicated) – by cause – 2014 (Figure 47)



Excluding third party damage Crude oil 222 949 642

Condensate 21 100 42

Processed oil 8 34 17

Unspecified oil 7 29 8

Third party damage Crude oil 65 276 57

Condensate 3 11 9

Processed oil 1 2 0


Table A.30: Oil spills 10–100 barrels (where cause was indicated) – by material spilled – 2014




Excluding third party damage Africa 29 132 14

Asia/Australasia 1 3 No data

Europe 8 27 14

FSU 80 288 288

Middle East 26 100 67

North America 101 517 314


13 45 12

Third party damage Africa 60 225 43

Asia/Australasia 2 9 9

Europe 0 0 0

FSU 0 0 0

Middle East 2 9 7

North America 3 23 0


2 22 8


Table A.31: Oil spills 10–100 barrels (where cause was indicated) (by region) – 2014



Excluding third party damage Onshore 237 998 710

Offshore 21 114 0

Third party damage Onshore 69 289 66

Offshore 0 0 0


Table A.32: Oil spills 10–100 barrels (where cause was indicated) – by location – 2014

77Appendix A



North America

South & Central

America

OVERALL


Quantity spilt (t) 5 5 2 409 33 374 1 828

Offshore Average size (t) 5.85 1.94 7.65 no data no data 0.53 14.68 7.01

Quantity spilt (t) 6 14 528 0 0 10 220 778

Unspecified Average size (t) no data no data no data no data no data no data no data 0.00

Quantity spilt (t) 0 0 0 0 0 0 0 0


Quantity spilt (t) 1 13 4 1,048 3 925 271 2,265

Offshore Average size (t) 58.89 5.66 13.52 no data no data 27.95 5.50 15.92

Quantity spilt (t) 471 68 1,434 0 0 224 33 2,229

Unspecified Average size (t) 0.56 no data no data no data no data no data no data 0.56

Quantity spilt (t) 1 no data 0 0 no data 0 no data 1


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


Quantity spilt (t) 27 3 401 225 1 122 430 1210

Unspecified Average size (t) 13.42 0.95 2.33 0.80 no data 5.26 no data 5.68

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

NB: Excludes spills <1 barrel in size.

Table A.33: Chemical spills (tonnes) onshore and offshore (by region)

79Glossary

Glossary

The following definitions have been used in this report. Some are generic, whereas others are specifically applicable to this report.

API American Petroleum Institute.

Barrel, Bbl In the energy industry, a barrel is 42 US gallons measured at 60° Fahrenheit. This is approximately 159 litres.

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

CH4 Methane, the principal constituent of natural gas. One of the primary greenhouse gases.

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

Crude oil A 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.

Cuttings The 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 fluid The circulating fluid (also called ‘mud’) used in the rotary drilling of wells to clean and condition the hole and to counterbalance formation pressure. See definitions for ‘water-based drilling fluid’ and ‘non-aqueous drilling fluid’ below.

E&P Exploration and Production (of hydrocarbons).

Emission rate Emissions 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, and pumps)

• Internal Combustion Engines• Heaters• Boilers / Reboilers

Energy intensity Energy consumed per unit of hydrocarbon production.

Exploration Study 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• Thermal Oxidizers

Flaring The 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 which cannot be used for commercial or technical reasons.

Fugitive emission, fugitive losses

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

Greenhouse gas A 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.

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

81Glossary

Hydrocarbon production

Quantity of hydrocarbon gas and/or liquids produced.

IPIECA The global oil and gas industry association for environmental and social issues.

Mud Common 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.

Non-aqueous drilling fluid

(NADF)

A drilling fluid in which the continuous phase is a water-immiscible fluid such as an oleaginous material (e.g. 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.

NMVOC Non-methane volatile organic compounds: all hydrocarbons other than methane that can vaporize at normal temperature and pressure.

Normalization To 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 normalization.

Offshore For 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.

Onshore For 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 combustion The local combustion of fuels by E&P companies to produce energy for their operations.

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

Processing The 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 categorized by the source of production and not the location where they occur, i.e. where production is offshore and discharges are generated from an onshore facility, the discharges are reported as offshore.

Production All production activities including production drilling, process and treatment, flaring and venting, in-field pipeline transport, and terminal operations.

(see Hydrocarbon production)

Purchased energy Energy purchased in the form of electricity or steam.

SO2 Sulphur dioxide (SO2) can result from the combustion of H2S and other sulphur containing compounds. In this report ‘SO2‘ refers to the sum of sulphur dioxide and sulphur trioxide (SO3) expressed as SO2 equivalent.

Source of emissions In the case of gaseous emissions refers to the process by which the emissions are released. Source categories are Energy, Flare, Vent, Fugitive losses and Unspecified.

Spill Any loss of containment from which the released material reaches the environment (i.e. is not retained within secondary or other confinement), irrespective of the quantity recovered. The volume of a spill represents the gross volume reaching the environment, not a net volume remaining in the environment after response.

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, or vandalism); excludes loss as a result of ‘acts of terrorism’/attacks on infrastructure.

83Glossary

Synthetics Synthetic 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 fluid

A 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.

Tonne A metric tonne; equivalent to 1,000 kilograms or 2,205 pounds.

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

Upstream industry Those operations within the industry to the point where the produced resource is metered into the transportation system. This includes Exploration and Production.

Venting The 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.

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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 industry’s 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 2014.

data series environmental performance indicators 2014 data

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