Environmental performance in the E&P industry 2010 data

Transcription

1 Environmental performance in the E&P industry data Report No. 466 October 2011 International Association of Oil & Gas Producers

2 P ublications Global experience The International Association of Oil & Gas Producers has access to a wealth of technical knowledge and experience with its members operating around the world in many different terrains. We collate and distil this valuable knowledge for the industry to use as guidelines for good practice by individual members. Consistent high quality database and guidelines Our overall aim is to ensure a consistent approach to training, management and best practice throughout the world. The oil & gas exploration & production industry recognises the need to develop consistent databases and records in certain fields. The OGP s members are encouraged to use the guidelines as a starting point for their operations or to supplement their own policies and regulations which may apply locally. Internationally recognised source of industry information Many of our guidelines have been recognised and used by international authorities and safety and environmental bodies. Requests come from governments and non-government organisations around the world as well as from non-member companies. Disclaimer Whilst every effort has been made to ensure the accuracy of the information contained in this publication, neither the OGP nor any of its members past present or future warrants its accuracy or will, regardless of its or their negligence, assume liability for any foreseeable or unforeseeable use made thereof, which liability is hereby excluded. Consequently, such use is at the recipient s own risk on the basis that any use by the recipient constitutes agreement to the terms of this disclaimer. The recipient is obliged to inform any subsequent recipient of such terms. This document may provide guidance supplemental to the requirements of local legislation. Nothing herein, however, is intended to replace, amend, supersede or otherwise depart from such requirements. In the event of any conflict or contradiction between the provisions of this document and local legislation, applicable laws shall prevail. Copyright notice The contents of these pages are The International Association of Oil & Gas Producers. Permission is given to reproduce this report in whole or in part provided (i) that the copyright of OGP and (ii) the source are acknowledged. All other rights are reserved. Any other use requires the prior written permission of the OGP. These Terms and Conditions shall be governed by and construed in accordance with the laws of England and Wales. Disputes arising here from shall be exclusively subject to the jurisdiction of the courts of England and Wales.

3 Environmental performance in the E&P industry data Report No: 466 October 2011

4 The environmental statistics for were derived from data provided by the following companies: Contributing companies Addax ADNOC BG BHP Billiton BP Cairn Energy Chevron CNOOC ConocoPhillips Dolphin Energy DONG E&P Eni E&P Division ExxonMobil GDF SUEZ (Formerly Gaz de France) Hess Corporation INPEX Kuwait Oil Company Maersk Oil Marathon MOL Nexen Oil Search OMV Petrobras Petronas Premier Oil PTT EP Qatar Petroleum Repsol YPF Shell Companies Statoil Suncor Talisman Energy Total Tullow Wintershall

5 Environmental performance in the E&P industry data Table of contents Executive summary 1 Deepwater Horizon accident...1 Gaseous emissions...1 Energy consumption...2 Flaring...2 Aqueous discharges...2 Non-aqueous drilling fluids (NADF) on cuttings...2 Spills...3 Introduction 4 Scope of data submissions 5 Detailed review: 1 Gaseous emissions Carbon Dioxide (CO 2 ) Methane (CH 4 ) Greenhouse Gas (GHG) emissions Non-Methane Volatile Organic Compounds (NMVOCs) Sulphur dioxide (SO 2 ) Nitrogen oxides Energy consumption 15 3 Flaring 17 4 Aqueous Discharges Quality (oil content) of produced water discharges Quantity of oil discharged in produced water per unit of production Produced Water Injection Non-Aqueous Drilling Fluids (NADF) on cuttings Non-aqueous base fluid discharged on cuttings Spills 25 Appendix A Data tables 31 Executive summary...31 Scope of data submissions...31 Detailed review Gaseous emissions Energy Consumption Flaring Aqueous discharges Non-Aqueous Drilling Fluids (NADF) on cuttings Spills...42 Appendix B Glossary 49 i

6 International Association of Oil & Gas Producers ii

7 Environmental performance in the E&P industry data Executive summary Over the past 12 years the International Association of Oil & Gas Producers (OGP) has collected environmental data from its member companies on an annual basis. The objective of this programme has been to allow member companies to compare their performance with other companies in the sector, leading, it is hoped, to improved and more efficient performance. The programme also contributes to the industry s wish to be more transparent about its operations. This report summarises information on exploration and production (E&P) activities carried out by contributing OGP member companies in. 36 member companies, working in 68 countries worldwide, have submitted data for the report. This total includes 2 companies reporting for the first time this year and 34 of the 35 companies that contributed data in. Information is aggregated at both global and regional levels and is expressed within 6 environmental indicator categories: Gaseous emissions; Energy consumption; Flaring; Aqueous discharges; Discharges of non-aqueous drilling fluids on cuttings; and Spills of oil and chemicals. These data represent oil & gas wellhead production of 2,268 million tonnes (about 33% of global production sales in the BP Energy Review 2011). However, regional coverage is uneven, ranging from almost all known production in Europe to 9% in the Former Soviet Union. Deepwater Horizon accident The data related to the Deepwater Horizon accident (i.e. spills and emissions) are not included in this report. The data were not provided to OGP due to uncertainty around the volumes released to the environment at the time of submission. Gaseous emissions Releases of gases to the atmosphere are an integral and inevitable part of exploration, production and processing operations. In, participating OGP member companies reported emissions of: 297 million tonnes of carbon dioxide (CO 2 ) equivalent to 133 tonnes of carbon dioxide per thousand tonnes of production; 2.6 million tonnes of methane (CH 4 ) equivalent to 1.2 tonnes of methane per thousand tonnes of production; 1.0 million tonnes of non-methane volatile organic compounds (NMVOC) equivalent to 0.5 tonne of NMVOC per thousand tonnes of production; 362 thousand tonnes of sulphur dioxide (SO 2 ) equivalent to 0.2 tonne of SO 2 per thousand tonnes of production; and 860 thousand tonnes of nitrogen oxides (NO X ) equivalent to 0.4 tonne of NO X per thousand tonnes of production. Normalised CO 2 emissions for were similar to the results. Normalised NMVOC and SO 2 emmissions were nearly 6% lower in compared with. Normalised CH 4 emissions increased in by approximately 4% and NO X increased by 3% compared with. OGP Report 442, OGP Publications: 1

8 International Association of Oil & Gas Producers Energy consumption Production of oil and gas requires significant quantities of energy for extraction, processing and transport. In many oilfields those energy needs are met by locally produced gas. In, OGP reporting companies consumed on average 1.5 GigaJoules of energy for every tonne of hydrocarbon produced unchanged compared with the average. As in previous years, data indicate that onshore production in was more energy intensive than offshore production. Regional analysis shows that operations in North were the most energy intensive (2.9 GigaJoules per tonne of hydrocarbon produced) while the Europe was the least energy intensive (1.1 GigaJoules per tonne). 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 which cannot be used due to commercial or technical reasons. Flaring is a major source of gaseous emissions detailed in this report. In, 15.5 tonnes of gas was flared for every thousand tonnes of hydrocarbon produced versus 17.6 tonnes in and 18.8 in. Reductions in flaring rates are predominantly driven by major infrastructure improvement projects which increase the capability to inject gas for reservoir maintenance and to deliver gas to markets. Reductions in flaring rates translate to reductions in CO 2 and other gaseous emission rates. Aqueous discharges Water from oil and gas production streams (produced water) is the most significant liquid discharge associated with E&P operations. For every tonne of hydrocarbon produced (including oil, condensates and gas), 0.6 tonne of produced water was discharged and 1.0 tonne of produced water was re-injected. The quality of produced water discharges is measured in terms of oil content. In, the average concentration of oil in produced water was 18 mg/l for onshore discharges and 12 mg/l for offshore discharges. When expressed in terms of oil production, overall, these discharges are equivalent to 7 tonnes of oil for every million tonnes of hydrocarbon produced. Comparison with data indicates that the average concentration of oil in produced water discharged decreased in by 6%. The average quantity of oil discharged per unit of hydrocarbon production decreased by 2%. Non-aqueous drilling fluids (NADF) on cuttings Although most drilling fluids are water-based, some conditions encountered during well drilling operations demand the properties that are only available from non-aqueous drilling fluids (NADFs). In, reporting companies discharged 26,091 tonnes of NADF on drill cuttings. 83% of these discharges contained Group III base fluids while 17% contained Group II fluids. There have been no reports of discharges of Group I fluids since reporting began. Definitions of Group I, II and III base fluids are provided in section 5.1 2

9 Environmental performance in the E&P industry data Spills For the purpose of this report, a spill is defined as any loss of containment that reaches the environment, irrespective of quantity recovered. In, participating OGP member companies reported 2,975 spills greater than 1 barrel in size, resulting in a normalised spill rate of 1.4 spills per million tonnes of hydrocarbon production. This rate was similar to the rate seen in of 1.5. The reported spills >1 bbl resulted in the release of a total of 9,741 tonnes of oil. The average quantity of oil spilled per unit of hydrocarbon production has fallen to 4.5 tonnes per million tonnes production, less than a quarter of the average for and half of the average for. Regional analysis shows that the average size of onshore spills is higher in than in the other regions. This high average can mainly be attibuted to wilful damage to facilities (sabotage) or mishaps during theft of crude from oil facilities, wells, flow lines or pipelines. For the first time this year, spills above 10 barrels in size have been broken down by cause. As mentioned earlier, Deepwater Horizon accident data are not included in this report. 3

10 International Association of Oil & Gas Producers Introduction Over the past 12 years, the International Association of Oil & Gas Producers (OGP) has collected environmental information from its member companies on an annual basis. The ultimate aim of this effort is to provide a representative statement on the environmental performance of the oil & gas E&P industry. 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; Discharges of non-aqueous drilling fluids on cuttings; and Spills. Data are collected annually for each of the categories above, on the basis of a set of definitions agreed by the OGP membership. 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. Quality assurance is an integral part of the reporting process and contributing companies are asked to provide information on the quality assurance systems that underpin their data submissions. Annual reports of activities in the years 2003 to and summary reports for activities in 2001 and 2002 have been published previously. Refer to OGP Publications: 4

11 Environmental performance in the E&P industry data Scope of data submissions 36 OGP member companies reported environmental information for, on average, 6 countries each. Data from 68 countries are represented in the report. The data represent 2,260 million tonnes of hydrocarbon production, approximately equivalent to 33% of world production as reported in the BP Energy Review for. To view the data from a geographical perspective, 7 regions have been defined. The percentage of total wellhead production (i.e. production including oil and gas consumed in field operations) reported by the participating companies for each of these regions in relative to the regional sales-based production volumes reported in the BP Energy Review is shown in the figure below. Percentage of total production Australasia Europe FSU Middle East North South Production figures in this report include oil and gas volumes consumed in operations and thus may exceed sales volumes reported in BP statistical review. This report only reflects the performance of the OGP member companies that have provided data. However where the degree of coverage is highest, for example in Europe where a high percentage of hydrocarbon production is represented, the information can be taken to approximate industry performance. In, Australasia, the Middle East, and North and South, the data give a broad indication of industry performance. For the former Soviet Union (FSU), data reported by participating companies represent just 9% of the total sales production for that region. Data for this region are therefore only representative of the performance of those companies reporting and not of the industry as a whole. Consequently, in the analysis of the data from this area, the information is shown on the charts as a grey bar, but is not included in cross-regional comparisons. Similarly, in previous years hydrocarbon production reported for the Middle East has been too low to be considered representative for the region. In, however, the production reported for the region reached 20% of known production and in it reached 22%. Thus, and results for the Middle East (for most metrics) are coloured in the graphs and included in the cross-regional comparisons, while pre- results are shown as grey bars in the graphs. As an exception, however, because of minimal reporting of Aqueous Discharges among participating companies with operations in the Middle East, the Aqueous Discharge data from that region cannot be considered to be representative of the region. In the Aqueous Discharges and Energy sections, all results for the Middle East are shown as grey bars and are excluded from the cross-regional comparisons. Global averages are calculated using data from all regions, including those from the FSU and the Middle East regions. 5

12 International Association of Oil & Gas Producers The number of companies reporting has fluctuated between years. Data are presented on a normalised basis to help control for this effect. Nevertheless, normalised performance indicator results may be influenced by changes in the list of reporting companies as well as changes in mixtures of assets held by the participating companies between years. Differences between years for participating companies may also, in some cases, reflect changes in calculation methodology applied or reporting definitions. Thus, though the coverage of E&P activities is good, changes in results may not necessarily reflect actual changes in performance. Normalised analyses are only possible when both the metric to be normalised (emissions, discharges, spills) and the normaliser (hydrocarbon production, produced water) data are available. 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. Coverage for the analyses is presented below. Percentage of reported production included in normalised analyses Australasia Europe FSU Middle East North South All regions Gas emissions CO 2 100% 100% 100% 100% 88% 100% 100% 98% CH 4 100% 87% 100% 100% 88% 100% 100% 96% NMVOC 100% 72% 98% 100% 81% 98% 100% 92% SO 2 100% 72% 98% 100% 88% 98% 100% 92% NO X 100% 73% 98% 100% 88% 98% 100% 93% Energy consumed 99% 100% 100% 100% 52% 100% 100% 92% Flaring 99% 95% 99% 99% 100% 99% 100% 99% Oil discharged in produced water 97% 94% 97% 92% 46% 85% 92% 86% Oil spills 98% 86% 97% 92% 93% 95% 96% 94% In, data on the source types of gaseous emissions (eg energy, flare, vent, fugitive emissions, and other) were collected for the first time. It was recognised that not all participating companies would be able to contribute data at that level of detail in the beginning; nevertheless, data broken down by source cover roughly half of the gaseous emissions reported for and. It is expected that this information will be helpful in understanding some of the trends in the data as well as to help indicate areas for improvement. Data coverage for the breakdown is expected to improve over time. The current year data shown in this report are based on best available information provided by member companies at time of publication. Data for previous years shown in this report are normally based on data published in previous years reports. However, in some cases, corrections provided by member companies have been made to data for previous years when these corrections significantly impact regional or global results. 6

13 Environmental performance in the E&P industry data Detailed review: 1 Gaseous emissions Releases of gases to the atmosphere are an integral and inevitable part of exploration, production and processing operations. The principal (routine) sources are flaring, venting, turbine and engine operation, fluids processing and fugitive losses (for example from pumps, gas driven valves, flanges and pipes). Non-routine and emergency emissions can arise from well testing, emergency flaring and gas venting. Gaseous emissions covered in this report are those considered most relevant from process control as well as regulatory perspectives. They are: carbon dioxide (CO 2 ), methane (CH 4 ), non-methane volatile organic compounds (NMVOC), sulphur dioxide (SO 2 ) and nitrogen oxides (NO X ), and separately, greenhouse gases (CO 2 + CH 4 expressed as CO 2 equivalent). Given the wide range of sources of gaseous emissions, it is not practicable (or possible) to measure every single release individually. Industry has, however, developed and updated detailed guidance methodologies to calculate and estimate emissions and losses. Since companies may use a variety of estimation techniques care must be taken when interpreting aggregated data. A number of factors affect the quantity of gases emitted from E&P petroleum industry operations. Consequently, understanding the variations in performance in terms of normalised emission ratios is complex. These factors include: Presence or absence of infrastructure for gas sales Gas-oil ratio Reservoir and field characteristics Use of hydrocarbon recovery techniques Regulatory and contractual aspects Location and logistics Age of the fields The following sub-sections present the overall emission data for the years 2004 to and regional emission data for to. In, participating OGP member companies reported emissions of: 297 million tonnes of carbon dioxide (CO 2 ) equivalent to 133 tonnes of carbon dioxide per thousand tonnes of production; 2.6 million tonnes of methane (CH 4 ) equivalent to 1.2 tonnes of methane per thousand tonnes of production; 1.0 million tonnes of non-methane volatile organic compounds (NMVOC) equivalent to 0.5 tonne of NMVOC per thousand tonnes of production; 362 thousand tonnes of sulphur dioxide (SO 2 ) equivalent to 0.2 tonne of SO 2 per thousand tonnes of production; and 860 thousand tonnes of nitrogen oxides (NO X ) equivalent to 0.4 tonne of NO X per thousand tonnes of production. Normalised figures for emissions (see Figure 1) are broadly consistent with data published for activities in See for example: Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions (2003), joint OGP/API/IPIECA report, (in revision) Compendium of Greenhouse Gas Emission Estimation Methodologies for the Oil & Gas Industry, API, Sangea Energy and Emissions Estimating System, API, 7

14 International Association of Oil & Gas Producers Figure 1 Emissions per thousand tonnes hydrocarbon production tonnes per thousand tonnes CH 4 NMVOC SO 2 NO X CO 2 GHG 0 GHG: Total GreenHouse Gases (CO 2 + CH 4 expressed as CO 2 equivalent) Note: As N 2 O contributes only to a small fraction to greenhouse gas emissions by the E&P activities, it has not been included here. 8

15 Environmental performance in the E&P industry data 1.1 Carbon Dioxide (CO 2 ) Carbon dioxide emissions represent the largest gaseous release (in terms of mass) from the E&P industry. Emissions occur principally from the flaring and combustion of fuels for energy production and are therefore a function of the type and quantity of fuel burned. Carbon dioxide releases may also occur where CO 2 is used for enhanced petroleum recovery or where it is stripped from the natural reservoir gases to meet sales specifications Emissions per unit of production Global CO 2 emissions normalised to hydrocarbon production for were 133 tonnes of CO 2 per thousand tonnes of production, as shown in Figure 1.1.1a. Regional averages for quantity of carbon dioxide emissions per 300 unit of production vary from 52 to 206 tonnes of carbon dioxide 250 per thousand tonnes of hydrocarbon production, as shown in 200 Figure 1.1.1b. In the range was between 54 and 215 tonnes 150 per thousand tonnes of production. Historically, normalised carbon dioxide emissions were higher in than other regions, reflecting more widespread flaring of associated gas than in other parts of the world. This Figure 1.1.1b: was related to the limited infrastructure that existed to market the gas. In recent years, however, projects have been implemented to improve the infrastructure and reduce flaring. As a result, CO 2 emissions rates in are declining towards levels seen in other regions. Differences between the other regions, where gas markets are more developed, largely reflect differences in energy intensity Emissions by source The source was specified for 56% of the reported carbon dioxide emissions. Where the source is specified, 58% of the reported carbon dioxide emissions are from energy use, 38% are from flaring and 4% are attributable to venting, as shown in Figure 1.1.2a Figure 1.1.1a: CO 2 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production CO 2 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production 177 Australasia 74 Europe 133 FSU Middle East Figure 1.1.2a: CO 2 emissions by source Note: excludes emissions where the source is not specified Vents 4% 52 Flare 38% Energy 58% 166 North 144 South 9

16 International Association of Oil & Gas Producers 1.2 Methane (CH 4 ) After carbon dioxide, methane is the next largest emission (in terms of mass) by the E&P industry. It is emitted from sources including process vents, gas-driven pneumatic devices and tank vents. It also escapes as fugitive emissions from process components (valves, flanges, etc) that carry process streams containing significant quantities of methane. In addition, some methane emissions result from incomplete combustion of hydrocarbons in turbines, engines and flare equipment Emissions by unit of production Normalised CH 4 emissions increased 3.5% compared with, as indicated in Figure 1.2.1a. Regional averages for methane emissions expressed per unit of 3.0 production vary from 0.2 to 2.5 tonnes of methane per thousand tonnes of hydrocarbon 2.5 production, as shown in Figure b. In, the range was between 0.1 and 2.7 tonnes per 1.5 thousand tonnes of production. Emissions intensity for Europe and the Middle East is lower than for other regions. In Europe this is partly due to low levels of flaring and venting in the region as well as to stringent Figure 1.2.1b: regulatory controls that limit fugitive emissions. In the other regions there are higher rates of natural gas flaring and venting in certain types of production facilities Emissions by source The source was specified for 56% of the total methane emissions reported. Where the source is specified, the largest portion of methane emissions, 41%, is from vents (including venting, vessel loading, tank storage, etc.); 26% is from flaring, 20% is from fugitive losses and 13% is from energy use, as shown in Figure 1.2.2a Figure 1.2.1a: Australasia 2005 CH 4 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Europe FSU Middle East 1.18 CH 4 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Vents 41% 1.6 North 1.3 South Figure 1.2.2a: CH 4 emissions by source Note: excludes emissions where the source is not specified Energy 13% Flare 26% Fugituve losses 20% 10

17 Environmental performance in the E&P industry data 1.3 Greenhouse Gas (GHG) emissions For E&P activities, CO 2 and CH 4 are the principal contributors to greenhouse gas emissions, with other gases such as N 2 O playing a minor role. The CO 2 and CH 4 data presented above are used to calculate an estimate of the GHG emissions for the contributing OGP reporting companies, using the standard conversion to CO 2 equivalent (GHG = CO x CH 4 ) Emissions per unit of production The average based on reported data of 158 tonnes of GHG per thousand tonnes of hydrocarbon production is almost unchanged compared to that seen in previous years. See Figure 1.3.1a. Regional averages for quantity of greenhouse gas emissions per 300 unit of production vary from 55 to 238 tonnes of greenhouse gas 250 per thousand tonnes of hydrocarbon production, as shown in 200 Figure 1.3.1b. In the range was between 56 and 246 tonnes 150 per thousand tonnes of production. Figure 1.3.1b: Emissions by source The source was specified for 50 56% of the total reported greenhouse gas emissions. Where the source is specified, 51% of the reported greenhouse gas emissions are from energy 0 use, 36% are from flaring, 10% are from venting or vents and 3% are attributable to fugitive losses, as shown in Figure 1.3.2a. Figure 1.3.1a: Australasia GHG emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Europe FSU Middle East GHG emissions per unit of production tonnes per thousand tonnes of hydrocarbon production North 171 South GHG: Total GreenHouse Gases (CO 2 + CH 4 expressed in CO 2 equivalent) Figure 1.3.2a: GHG emissions by source Note: excludes emissions where the source is not specified Vents 10% Fugituve losses 3% Flare 36% Energy 51% GHG: Total Greenhouse Gases (CO 2 + CH 4 expressed as CO 2 equivalent) 11

18 International Association of Oil & Gas Producers 1.4 Non-Methane Volatile Organic Compounds (NMVOCs) NMVOC emissions mainly occur from non-combustion sources such as venting and fugitive releases (including crude oil loading). In addition, NMVOCs are emitted in the exhaust of combustion equipment and are, therefore, a function of the nature and quantity of fuel burnt, the type of combustion device used and the mode of operation Emissions per unit of production Normalised NMVOC emissions were 0.50 tonnes per thousand tonnes of hydrocarbon production, a reduction of 6% compared with. See Figure 1.4.1a. Regional averages for quantity of NMVOC emitted per unit of production vary from 0.3 to 0.8 tonne per thousand tonnes of hydrocarbon production, as shown in Figure 1.4.1b. Figure 1.4.1b: In the range was between 0.2 and 1.0 tonne per thousand 1.2 tonnes of production. NMVOC emissions are highest 1.0 in (0.8 tonne of NMVOC per thousand tonnes of production). The second highest region 0.8 is Australasia with a rate of tonne of NMVOC per thousand tonnes of production Emissions by source 0.2 The source was specified for 40% of the total NMVOC emissions 0.0 reported. Where the source is specified, 45% of NMVOC emissions come from flaring, 37% from venting or vents, 13% from fugitive losses and 5% from energy use, as shown in Figure 1.4.2a. Figure 1.4.1a: NMVOC emissions per unit of production tonnes per thousand tonnes of hydrocarbon production NMVOC emissions per unit of production tonnes per thousand tonnes of hydrocarbon production 0.7 Australasia 0.3 Europe 0.50 FSU 0.3 Middle East 0.6 North 0.6 South Figure 1.4.2a: NMVOC emissions by source Note: excludes emissions where the source is not specified Energy 5% Vents 37% Flare 45% Fugituve losses 13% 12

19 Environmental performance in the E&P industry data 1.5 Sulphur dioxide (SO 2 ) Sulphur dioxide emissions by the E&P industry arise through oxidation during combustion of sulphur naturally contained within hydrocarbon fuels or flared gas. The rate of emission therefore is principally a reflection of the sulphur content of produced hydrocarbons, which varies widely depending on the nature of the hydrocarbon produced. Flaring of gases from the sulphur removal process represents one of the biggest sources of SO 2, together with flaring of associated gas containing H 2 S Emissions per unit of production Normalised SO 2 emissions were 0.17 tonnes per thousand tonnes of hydrocarbon production, a reduction of 6% compared with results. See Figure 1.5.1a. Regional averages for quantity of SO 2 emissions expressed per unit of production vary from 0.04 to tonne per thousand tonnes of hydrocarbon production, as shown in Figure 1.5.1b. In 0.6 the range was between 0.03 to 0.56 tonne per thousand tonnes of production. 0.4 Europe and Australasia have the lowest average normalised emissions of SO 2, 0.04 and tonne per thousand tonnes of hydrocarbon production respectively Emissions by source Figure 1.5.1b: 0.0 Figure 1.5.1a: Australasia SO 2 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Europe FSU Middle East 0.17 SO 2 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production North 0.09 South The source was reported for 45% of the total SO 2 emissions. Where the source is specified, the largest percentage of sulphur dioxide emissions, 67%, relate to flaring. 30% of the sulphur dioxide emissions were from energy use and the remaining 3% were from venting or vents, as shown in Figure 1.5.2a. Figure 1.5.2a: SO 2 emissions by source Note: excludes emissions where the source is not specified Vents 3% Energy 30% Flare 67% 13

20 International Association of Oil & Gas Producers 1.6 Nitrogen oxides Emissions of nitrogen oxides (principally nitric oxide and nitrogen dioxide, expressed as NO X ) occur almost exclusively from the combustion of natural gas or other fuels. These emissions are a function of the combustion peak temperature, and therefore of the type and operation of combustion device. NO X emission figures are frequently estimated rather than measured directly. In consequence, they are strongly dependent upon the calculation methodology and thus it can be difficult to get comparable data Emissions per unit of production Global NO X emissions normalised to hydrocarbon production for were 0.40 tonnes per thousand tonnes of production, approximately 5% higher than the results. See Figure Figure 1.6.1b: 1.6.1a. Regional averages for quantity of 0.8 NO X emitted per unit of production vary from 0.2 to 0.7 tonne 0.7 of NO X per thousand tonnes 0.6 of hydrocarbon production, as 0.5 shown in Figure 1.6.1b. In the range was between 0.1 and tonne per thousand tonnes of 0.3 production. Normalised NO X emissions are 0.2 highest in the North and South 0.1 regions, each with an 0.0 average of 0.69 tonne of NO X per thousand tonnes of hydrocarbon production. In North this reflects the high energy intensity. The Middle East region has the lowest normalised NO X emissions of 0.2 tonne NO X per thousand tonnes of hydrocarbon production Emissions by source The source was reported for 49% of the total nitrogen oxide emissions reported. Where the source is specified, 92% of nitrogen oxide emissions are from energy use. The remaining 8% of nitrogen oxide emissions are from flaring, as shown in Figure 1.6.2a. Figure 1.6.1a: Australasia NO X emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Europe FSU 0.39 Middle East 0.40 NO X emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Flare 8% 0.2 Energy 92% 0.7 North 0.7 South Figure 1.6.2a: NO X emissions by source Note: excludes emissions where the source is not specified 14

21 Environmental performance in the E&P industry data 2 Energy consumption The energy used to produce oil and gas covers a range of activities. These include: driving pumps that produce the hydrocarbons (and any associated produced water); heating produced oil for separation; producing steam for enhanced oil recovery; driving the pumps to re-inject produced water, inject water for water-flooding and transport the produced oil through pipelines; powering compressors to re-inject produced gas or to export it through pipelines; and driving turbines to generate electricity needed for operational activities, including logistics, and for living quarters (eg at offshore platforms). Energy consumption will vary widely depending upon the specific local circumstances and operational conditions. For example, mature or remote fields usually consume more than the other fields. In, OGP reporting companies consumed on average 1.5 GigaJoules of energy for every tonne of hydrocarbon produced, as shown in Figure 2.1. This is virtually unchanged compared with the average. As in previous years, data indicate that onshore production in was more energy intensive than offshore production. The majority of energy requirements were met by combustion of fuels on-site rather than by purchase of electricity or steam. No breakdown was specified for 16% of the total; where a breakdown was provided, 94% was derived from on-site combustion 6% was purchased. Figure 2.1: Energy consumed per unit of hydrocarbon production GigaJoules per tonne 1.5 Unspecified energy Purchased energy On-site combustion

22 International Association of Oil & Gas Producers In Figure 2.2, the (overall) energy consumption is normalised against the quantity of hydrocarbons produced for each region. This analysis shows that operations in North were the most energy intensive (2.9 GigaJoules per tonne of hydrocarbon produced), while Europe was the least energy intensive (1.1 GigaJoules per tonne). Figure 2.2: Energy consumption per unit of hydrocarbon production by region GigaJoules per tonne Australasia Europe FSU Middle East North South 16

23 Environmental performance in the E&P industry data 3 Flaring Flaring is the controlled burning of natural gas produced in the course of E&P operations. It includes the controlled and safe burning of gas which cannot be used because of commercial or technical reasons. Flaring is a major source of gaseous emissions detailed in this report. In, 15.5 tonnes of gas was flared for every thousand tonnes of hydrocarbon produced versus 17.6 in and 18.8 in as shown in Figure 3.1. Figure 3.1: Flaring per unit of hydrocarbon production by region Tonnes per thousand tonnes NB: representative flaring data were only gathered from 2006 onwards. Figure 3.2 shows the flaring per unit of hydrocarbon production as reported by the participating companies by region. Figure 3.2: Flaring per unit of hydrocarbon production by region Tonnes per thousand tonnes Australasia Europe 4.0 FSU Middle East North 13.0 South Intensities are higher in the region where there is limited gas sales infrastructure. Projects in that are increasing the capability to inject gas for reservoir maintenance and to deliver gas to markets have helped reduce flare from 60 tonnes of gas flared for every thousand tonnes of hydrocarbon produced in to 50 in. This reduction is reflected in the overall average as the total hydrocarbon flared in is more than 50% of the total for all regions. 17

24 International Association of Oil & Gas Producers 18

25 Environmental performance in the E&P industry data 4 Aqueous Discharges Produced 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 oil and gas fields age. As context, the worldwide volume of produced water reported in this database in was approximately 1.5 times that of hydrocarbon production. Discharge of produced water is regulated in most countries. Regulations usually vary between onshore and offshore, and from one country to another. Differences in onshore and offshore regulations reflect differing environmental conditions and sensitivities. For example, salt content and biochemical oxygen demand (BOD) can be important aspects where discharges are to rivers or where these may have an impact on potable aquifers. These factors are less important for offshore discharges where the focus is more on the oil content of produced water. 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. Aqueous discharge covers the discharge of produced water, mainly produced formation water. In, where the location was specified, approximately 87% of water discharged was from offshore operations and 13% was from onshore operations. For every tonne of hydrocarbon produced in, 0.6 tonne of produced water was discharged and 1.0 tonne of produced water was re-injected. In, 0.5 tonne of produced water was discharged and 0.9 tonne was reinjected. The overall average oil content in produced water discharges was 12.6 mg/l, compared to 13.3 mg/l in and 14.8 mg/l in. the average oil content in produced water was 11.6 mg/l, whilst onshore it was 17.9 mg/l. (See Figure 4.1) 4.1 Quality (oil content) of produced water discharges Figure 4.1a Oil discharged per unit of produced water discharged milligrammes oil per litre of produced water discharged Regional averages for the oil content of produced water discharged vary onshore from 1.6 to 35mg/l (Figure 4.1c) while offshore they vary from 10 to 16mg/l (Figure 4.1b). 19

26 International Association of Oil & Gas Producers Figure 4.1b: Oil content of produced water discharged offshore milligrammes oil per litre of produced water discharged (equivalent to tonnes per million tonnes) Australasia Europe FSU Middle East North South Figure 4.1c: Oil content of produced water discharged onshore milligrammes oil per litre of produced water discharged (equivalent to tonnes per million tonnes) Australasia Europe FSU Middle East North South 4.2 Quantity of oil discharged in produced water per unit of production Regional averages for the quantity of oil discharged by unit of production of hydrocarbons vary, onshore (see Figure 4.2.b), from a few kg per million tonnes in South and Europe, to 9.4t/10 6 t in Australasia, while offshore (Figure 4.2.a) they vary from 8t/10 6 t in North to 14t/10 6 t in Australasia. The offshore average for the Australasia region shows an ongoing reduction over the 3-year period shown (down by 24% compared with ). This is partly the result of an increase in the reinjection of produced water in the region, improved equipment maintenance, increased production and the decommissioning of a field. In addition, the onshore/offshore split could not be made for some data so they were reported as unspecified. As noted above, the difference between the overall averages onshore and offshore reflects the fact that produced water is largely reinjected onshore (where environmental sensitivities to produced water especially salt are generally high) while the offshore environment is generally less sensitive to produced water discharges. 20

27 Environmental performance in the E&P industry data Figure 4.2a: Oil discharged per unit of production offshore tonnes per million tonnes of hydrocarbon production Australasia Europe FSU Middle East North South Figure 4.2b: Oil discharged per unit of production onshore tonnes per million tonnes of hydrocarbon production Australasia Europe 0 FSU Middle East North 0 South 4.3 Produced Water Injection As stated previously, produced water is often injected back into reservoirs (reinjection) to improve hydrocarbon recovery or into other geological strata for disposal., where disposal to surface is often constrained by regulatory and environmental concerns, injection of produced water is the principal disposal route with 89% of water being returned below ground (see Figure 4.3b). In the n region, reinjection of produced water has increased from 43% in to 90% in. This is the result of continuing efforts to reduce produced water discharges. (Figure 4.3a), where de-oiled produced water can be discharged to sea with limited impact in the majority of locations, there is much less reinjection (average 20%). Exceptions to this are locations where injection would be beneficial to the management of the reservoir or where environmental sensitivity is considered to be high. In Europe, 31% of the offshore produced water was reinjected while in just 10% was reinjected. Over the 3 years shown, there is a slight increase in the quantity of water re-injected compared to water discharged both onshore and offshore. 21

28 International Association of Oil & Gas Producers Figure 4.3a: Percentage of produced water re-injected offshore by region expressed as percent total produced water generated offshore Australasia Europe FSU Middle East North South Figure 4.3b: Percentage of produced water re-injected onshore by region expressed as percent total produced water generated onshore Australasia Europe FSU Middle East North South 22

29 Environmental performance in the E&P industry data 5 Non-Aqueous Drilling Fluids (NADF) on cuttings While most 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, stability 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, both of which may be required to develop new reservoirs or to improve recovery from previously identified resources. OGP reports NADFs according to the following classifications : Classification Base fluid Aromatic (%) PAH (%) Group I Diesel and conventional mineral oil >5.0 >0.35 Group II Low toxicity mineral oil Group III Enhanced mineral oil Synthetics (esters, olefins, paraffins) <0.5 <0.001 In the past, diesel-based and mineral oil-based fluids (Group I fluids) were used to address these technical challenges, but it was recognised that the discharge of cuttings with adhering diesel or oil-based muds might cause adverse environmental impacts. Thus, less harmful low-toxicity mineral oil fluids (Group II) and later more sophisticated drilling fluids (Group III) 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 NADF adhering to cuttings that are discharged to the marine environment. NADFs as such are not discharged. 5.1 Non-aqueous base fluid discharged on cuttings The following chart, Figure 5.1, provides a regional view of adhered base fluid quantities on cuttings discharged to the sea while drilling with NADFs. It should be noted that information on NADF discharges has been provided by a relatively small number of companies (15) and they therefore cannot represent overall industry performance. No data were received on discharges of Group I fluids and, although it is not possible to state definitively that Group I fluids are no longer discharged, there is some evidence that this is indeed the case. Regional analysis shows that, for the companies reporting NADF cuttings and discharges in, cuttings with Group III fluids (83% of the total reported) were discharged in all regions except the Middle East, and that discharges of cuttings with Group II fluids (1% of the total reported) only took place in (352 tonnes) and Europe (1 tonne). Discharges reported as Unspecified (16% of the total) occurred in all regions except Europe and the Middle East. No discharges of cuttings with Group I fluids were reported in. Absolute values rather than normalised values are shown in Figure 5.1. Drilling discharges are not normalised because drilling activity is not directly linked to hydrocarbon production. The number of wells that are drilled varies from year to year for various reasons including the prices of oil and natural gas as well as economic factors. Absolute volumes reported can also vary with the number or mix of companies contributing cuttings-related data between years. Classification is defined in OGP Report 342, Environmental aspects of the use of non-aqueous drilling fluids associated with offshore oil & gas operations, May

30 International Association of Oil & Gas Producers Figure 5.1: Total base fluid (NADF) discharges to sea, by region; tonnes ,203 20,369 NADF Unspecified NADF Group III NADF Group II , ,814 1, Australasia Europe FSU Middle East ,713 2,419 1,230 North 2,950 2,778 3,035 South Note: No Group 1 NADF discharges were reported in -; NDAF discharges were only reported by 15 companies in 24

31 Environmental performance in the E&P industry data 6 Spills Spills 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 purposes of this report, spills are defined as any loss of containment that reaches the environment, irrespective of quantity recovered. Spills may have a number of causes such as equipment failure (including corrosion), operating errors, sabotage and theft. The majority of spills in the E&P sector of the oil & gas industry are oil spills, which include spills of condensate and petroleum related products. Chemical spills with release to the external environment occur only infrequently and quantities released are generally small. Relatively few reports of chemical spills have been received and the data for these are presented in Appendix A. Deepwater Horizon accident In a large volume of oil was spilled as a result of the Deepwater Horizon accident. Due to the current uncertainty around the volumes spilled the data related to this incident are not reported here. Oil Spills In, companies reported a total of 7,291 spills. Of these, 4,316 (59%) were spills of less than one barrel in volume, amounting to a total of 74 tonnes of oil. Because of the small cumulative volume involved and, as some companies do not report spills less than 1 bbl in size, these <1 bbl size spills are not included in the detailed analysis provided below. In, 2,975 oil spills greater than 1 bbl in size were reported. 83.4% of the reported oil spills occurred onshore and 5.4% offshore. The location was not specified for the remaining 11%. Figure 6.1 shows the total number of spills normalised per unit of hydrocarbon production onshore and offshore. The normalised rate for was 1.4 spills per million tonnes of production versus rates of 1.5 and 1.4 for and, respectively. The normalized rate of spills onshore is higher than that offshore. Figure 6.1: Number of oil spills > 1 bbl per unit of hydrocarbon production spills per million tonnes Figure 6.2 shows the number of spills normalised per unit hydrocarbon production by region. Rates for vary from 0.3 spills per million tonnes of production in Europe to 8.2 spills per million tonnes of production in South. For information, data relating to the Montara spill do not appear in the Environmental Performance Indicators Report (OGP report 442) as they were not included in the data submission of the operator. 25