Environmental performance in the E&P industry 2009 data

Transcription

1 Environmental performance in the E&P industry data Report No. 442 October 2010 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: 442 October 2010

4 The environmental statistics for were derived from data provided by the following companies: Contributing companies 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 NIGC Oil Search OMV Petrobras Petronas Premier Oil PTT EP Qatar Petroleum Repsol YPF Shell Companies Statoil Suncor Talisman Energy Total Wintershall

5 Environmental performance in the E&P industry data Table of contents Executive summary 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 Quantity of oil discharged in produced water per unit of production Quality (oil content) of produced water discharges Produced water injection Non-Aqueous Drilling Fluids (NADF) on cuttings Non-aqueous base fluid discharged on cuttings Spills 25 Appendix A Data tables 29 Executive summary...29 Scope of data submissions...29 Detailed review Gaseous emissions Energy consumption Flaring Aqueous discharges Non-Aqueous Drilling Fluids (NADF) on cuttings Spills...40 Appendix B Glossary 47 i

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7 Environmental performance in the E&P industry data Executive summary Over the past 11 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 & production (e&p) activities carried out by contributing OGP member companies in. 35 member companies, working in 66 countries worldwide, have submitted data for the report. This total includes 3 companies reporting for the first time this year, in addition to the 32 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 and gas wellhead production of 2,352 million tonnes (about 36% of global production sales in the BP Energy Review ). However, regional coverage is uneven, ranging from almost all known production in Europe to 10% in the Former Soviet Union. Gaseous emissions In, participating OGP member companies reported emissions of: 302 million tonnes of carbon dioxide (CO 2 ) equivalent to 139 tonnes of carbon dioxide per thousand tonnes of production; 2.4 million tonnes of methane (CH 4 ) equivalent to 1.1 tonnes of methane per thousand tonnes of production; 1.1 million tonnes of non-methane volatile organic compounds (NMVOC) equivalent to 0.5 tonne of NMVOC per thousand tonnes of production; 390 thousand tonnes of sulphur dioxide (SO 2 ) equivalent to 0.2 tonne of SO 2 per thousand tonnes of production; and 843 thousand tonnes of nitrogen oxides (NO X ) equivalent to 0.4 tonne of NO X per thousand tonnes of production. Global emissions normalised to hydrocarbon production for CO 2 and NO X for were approximately 2% lower than the results. Normalised NMVOC emissions decreased by 9% versus, partly due to a change for some companies in estimation and calculation methods and reduced gas flaring. Normalised CH 4 emissions increased by 12% compared to. This increase was driven largely by new producing facilities in existing operations and the introduction of data for operations and companies not previously included. Normalised SO 2 emissions increased by 6% compared to results, partly due to an increase in sour gas flare and to the introduction of data for operations and companies not previously included. Regional analysis confirms an association between the level of development of infrastructure required to collect, market and use the gas associated with the production of oil in a region and the level of gaseous emissions of CO 2 and CH 4. OGP Report 429, OGP Publications: 1

8 International Association of Oil & Gas Producers Energy consumption Production of oil and gas requires significant quantities of energy for extraction, process 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. This was 9% higher than 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 were the most energy intensive (3.1 GigaJoules per tonne of hydrocarbon produced), while the Middle East was the least energy intensive (1.0 GigaJoules per tonne). This is partly due to lower levels of processing of reservoir fluids (oil, gas and water). Flaring Flaring is the controlled burning of natural gas produced in the course of petroleum exploration & 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, 17.5 tonnes of gas was flared for every thousand tonnes of hydrocarbon produced versus 18.8 in and 20.4 in. These reductions in flaring rates are driven by major infrastructure improvement projects which are increasing 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 (including oil, condensates and gas) produced, 0.5 tonne of produced water was discharged and 0.9 tonne of produced water was re-injected. The quality of produced water discharges is measured in terms of oil content. In, the average concentration of oil in produced water was 12 mg/l for onshore discharges and 14 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 9%. The average quantity of oil discharged per unit of hydrocarbon production decreased by 12%. 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 19,079 tonnes of NADF on drill cuttings. In the past, these NADFs have contained diesel or conventional mineral oil as the primary component (Group I fluids). However the industry has moved to NADFs using low toxicity mineral oil (Group II fluids) and, more recently, enhanced mineral oils and synthetics (Group III fluids). As a consequence of this shift, of the NADF discharged on drill cuttings in, 97% contained Group III base fluids, while 3% contained group II fluids. There were no reports of discharges of Group I fluids. 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 3,222 spills greater than 1 barrel in size, resulting in a normalised spill rate of 1.5 spills per million tonnes of hydrocarbon production. This rate was similar to the rate seen in of 1.4. The reported spills >1 bbl resulted in the release of a total of 40,126 tonnes of oil. The average quantity of oil spilled per unit of hydrocarbon production has risen to 19 tonnes per million tonnes production, more than twice the averages for and. There is significantly less oil spilled offshore than onshore. Spill volumes are usually dominated by a few incidents. In, the largest reported oil spill volume resulted from a single incident that occurred in Qatar, where 17,420 tonnes of crude oil (43% of the total) were spilled as a result of an onshore well blowout due to corrosion. 77% (13,400 tonnes) of the material spilled in that incident was recovered. Regional analysis shows that the average size of onshore spills is higher in the Middle East and than in the other regions. In the Middle East this is the direct result of the unusually large spill in Qatar. In the high average can mainly be attributed to equipment failure or to wilful damage to facilities (sabotage) or mishaps during theft of crude from oil facilities, wells, flow lines or pipelines. 3

10 International Association of Oil & Gas Producers Introduction Over the past 11 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. OGP report 359, 372, 383, 399, 414, 429, 339s & 347s, OGP Publications: 4

11 Environmental performance in the E&P industry data Scope of data submissions 35 OGP member companies reported environmental information for, on average, 7 countries each. Data from 66 countries are represented in the report. The data represent 2,352 million tonnes of hydrocarbon production, approximately equivalent to 36% 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 (ie 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 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 and South, the data give a broad indication of industry performance. For the former Soviet Union (FSU), data reported by participating companies represent just 10% 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 33%. 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 section all results for the Middle East are shown as grey bars and excluded from the crossregional comparisons. Global averages are calculated using data from all regions, including those from the FSU and the Middle East regions. 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, 5

12 International Association of Oil & Gas Producers 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 hydrocarbon production 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 South All regions Gas emissions per unit of production CO 2 100% 100% 100% 100% 66% 98% 100% 92% CH 4 100% 90% 100% 99% 66% 98% 100% 91% NMVOC 97% 79% 100% 100% 61% 96% 100% 87% SO 2 97% 78% 100% 100% 65% 96% 100% 88% NO X 97% 79% 100% 100% 65% 96% 100% 89% Energy consumed 100% 100% 99% 100% 66% 100% 100% 92% Flaring 100% 100% 100% 100% 100% 100% 100% 100% Oil discharged in produced water 90% 96% 93% 91% 31% 79% 92% 77% Oil spills 94% 95% 97% 99% 70% 100% 95% 91% 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 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 for. 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 Age of the fields The following sub-sections present the overall emission data for the years 2003 to and regional emission data for to. In participating OGP member companies reported emissions of: 302 million tonnes of carbon dioxide (CO 2 ) equivalent to 139 tonnes of carbon dioxide per thousand tonnes of production; 2.4 million tonnes of methane (CH 4 ) equivalent to 1.1 tonnes of methane per thousand tonnes of production; 1.1 million tonnes of non-methane volatile organic compounds (NMVOC) equivalent to 0.5 tonne of NMVOC per thousand tonnes of production; 390 thousand tonnes of sulphur dioxide (SO 2 ) equivalent to 0.2 tonne of SO 2 per thousand tonnes of production; and 843 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 GHG: Total GreenHouse Gases (CO 2 + CH 4 expressed as CO 2 equivalent) 0 OGP report 429, OGP Publications: 8

15 Environmental performance in the E&P industry data 1.1 Carbon Dioxide (CO 2 ) Emission of carbon dioxide is the largest gaseous release (in terms of mass) from the E&P industry. Emissions occur principally from 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 approximately 2% lower than the results, as shown in Figure 1.1.1a. Regional averages for quantity of carbon dioxide emissions per unit of production vary from 54 to 204 tonnes of carbon dioxide per thousand tonnes of hydrocarbon production, as shown in Figure 1.1.1b. In the range was between 71 and 233 tonnes 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 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 there 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. A steady increase is seen in reported CO 2 emissions in Australasia between and. This is due to the introduction of data for operations and/or companies not included in the previous years results Emissions by source The source was specified for 50% of the reported carbon dioxide emissions. Where the source is specified, 55% of the reported carbon dioxide emissions are from energy use, 42% are from flaring and 3% are attributable to venting and fugitive 300 losses. Figure 1.1.1b: 250 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 (overall 139) Australasia Europe FSU Middle East 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 by 12% compared to, as indicated in Figure 1.2.1a. This increase was driven largely by new producing facilities in existing operations and the introduction of data for operations and companies not previously included. Regional averages for methane emissions expressed per unit of production vary from 0.1 to 2.7 tonnes of methane per thousand tonnes of hydrocarbon production, as shown in Figure 1.2.1b. In the range was between 0.2 and 1.8 tonnes per thousand tonnes of production. Emissions intensity for Europe and the Middle East is lower than for other regions. In Europe this is partly due to low levels of flaring and venting in the region as well as to stringent regulatory controls that limit fugitive emissions. In the other regions there are higher rates of natural gas flaring and venting in certain types of production facilities. There is a notable increase in CH 4 emissions per unit of production in the Australasia region. This is partly due to new producing facilities in existing operations and the introduction of data for operations and/or companies not included in the previous years results Emissions by source The source was specified for 51% of the total methane emissions reported. Where the source is specified, the largest portion of methane emissions, 44%, is from vents (including venting, vessel loading, tank storage, etc.). 32% 3.0 are from flaring, 20% are from 2.5 fugitive losses and 4% are from energy use. 2.0 Figure 1.2.1b: Figure 1.2.1a: CH 4 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production CH 4 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production 2.7 (overall 1.1) Australasia Europe FSU Middle East South 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 163 tonnes of GHG per thousand tonnes is almost unchanged compared to that seen in previous years. See Figure 1.3.1a. Regional averages for quantity of greenhouse gas emissions per unit of production vary from 56 to 246 tonnes of greenhouse gas per thousand tonnes of hydrocarbon production, as shown in Figure 1.3.1b. In the range was between 74 and 262 tonnes per thousand tonnes of production. There is a notable increase in GHG emissions per unit of production in the Australasia region. This is partly due to new producing facilities in existing operations and the introduction of data for operations and/or companies not included in the previous years results Emissions by source The source was specified for 50% of the total reported greenhouse gas emissions. Where the source is specified, 48% of the reported greenhouse gas emissions are from energy use, 40% are from flaring, 9% are from venting or vents and 3% are attributable to fugitive losses. Figure 1.3.1a: GHG emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Figure 1.3.1b: GHG emissions per unit of production tonnes per thousand tonnes of hydrocarbon production 300 (overall 163) Australasia Europe FSU Middle East South GHG: Total GreenHouse Gases (CO 2 + CH 4 expressed in 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 decreased by 9% versus, partly due to a change for some companies in estimation and calculation methods and reduced gas flaring. See Figure 1.4.1a. Regional averages for quantity of NMVOC emitted per unit of production vary from 0.2 to 1.0 tonne per thousand tonnes of hydrocarbon production, as shown in Figure 1.4.1b. In the range was between 0.3 and 0.9 tonne per thousand tonnes of production. NMVOC emissions are highest in (1.0 tonne of NMVOC per thousand tonnes of production). The second highest regions are Australasia, and South, each with a rate of 0.7 tonne of NMVOC per thousand tonnes of production. The high intensity is the result of higher flaring rates that produce higher quantities of unburned NMVOCs. The average NMVOC emissions per unit of production reduced notably in Australasia and the Middle East. The reduction in Australasia is largely the result of a different approach to estimation and calculations of emissions by some reporting companies and a change in equipment utilisation. The average has fallen in the Middle East as the result of a reduction in gas flaring by one of the reporting companies Emissions by source The source was specified for 48% of the total NMVOC emissions reported. Where the source is specified, 46% of NMVOC emissions come from venting or vents, 37% from flaring, 12% from fugitive losses and 5% from energy use. Figure 1.4.1a: NMVOC emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Figure 1.4.1b: 1.2 NMVOC emissions per unit of production tonnes per thousand tonnes of hydrocarbon production (overall 0.53) Australasia Europe FSU Middle East South 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 increased by 6% compared to results, partly due to an increase in sour gas flare and to the introduction of data for operations and companies not previously included. See Figure 1.5.1a. Regional averages for quantity of SO 2 emissions expressed per unit of production vary from 0.03 to 0.56 tonne per thousand tonnes of hydrocarbon production, as shown in Figure 1.5.1b. In the range was between 0.03 and 0.76 tonne per thousand tonnes of production. Europe and Australasia have the lowest average normalised emissions of SO 2, 0.03 and 0.04 tonne per thousand tonnes of hydrocarbon production respectively. The increase in SO 2 emissions in is partly due to an increase in sour gas flare and the introduction of data for operations and/or companies not included in the previous year results. There is a notable decrease in SO 2 emissions for the Middle East region. This is partly because some members have altered the scope of their submissions to align with the OGP requirement to report only emissions under operational control, and partly due to a reduction in flaring in the region Emissions by source The source was reported for 52% of the total SO 2 emissions. Where the source is specified, the largest percentage of sulphur dioxide emissions, 65%, relate to flaring. 28% of the sulphur dioxide Figure 1.5.1b: emissions were from energy use 1.0 and the remaining 7% were from venting or vents. 0.8 Figure 1.5.1a: (overall 0.19) SO 2 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production SO 2 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Australasia 0.03 Europe FSU Middle East 0.10 South 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 approximately 2% lower than the results. See Figure 1.6.1a. Regional averages for quantity of NO X emitted per unit of production vary from 0.1 to 0.8 tonne of NO X per thousand tonnes of hydrocarbon production, as shown in Figure 1.6.1b. In the range was between 0.1 and 0.8 tonne per thousand tonnes of production. Normalised NO X emissions are highest in the region, with an average of 0.76 tonne of NO X per thousand tonnes of hydrocarbon production. This reflects the high energy intensity of n production. The Middle East region has the lowest normalised NO X emissions of 0.1 tonne NO X per thousand tonnes of hydrocarbon production. South is the region with the second highest NO X per unit of production. This is due to the use of diesel generators for power supply on offshore drilling platforms. Figure 1.6.1a: 0.5 NO X emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Emissions by source The source was reported for 48% of the total nitrogen oxide emissions reported. Where the source is specified, 90% of nitrogen oxide emissions are from energy use. The remaining 10% of nitrogen oxide emissions are from flaring Figure 1.6.1b: NO X emissions per unit of production tonnes per thousand tonnes of hydrocarbon production (overall 0.40) Australasia Europe FSU Middle East South 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 the operations and for living quarters (eg at offshore platforms). Energy consumption will vary widely depending upon the specific local circumstances and operational conditions. 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 a 9% increase compared to the average and is influenced by the introduction of energy and production data from companies operating in and the Middle East that had not previously reported energy or production data. 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, 95% was derived from on-site combustion 5% was purchased. 15

22 International Association of Oil & Gas Producers Figure 2.1: Energy consumed per unit of hydrocarbon production GigaJoules per tonne 1.5 Unspecified energy Purchased energy On-site combustion 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 were the most energy intensive (3.1 GigaJoules per tonne of hydrocarbon produced), while the Middle East was the least energy intensive (1.0 GigaJoules per tonne). This is partly due to lower levels of processing of reservoir fluids (oil, gas and water). Figure 2.2: Energy consumption per unit of hydrocarbon production by region GigaJoules per tonne (overall 1.5) Australasia Europe FSU Middle East 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, 17.5 tonnes of gas was flared for every thousand tonnes of hydrocarbon produced versus 18.8 in and 20.4 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 (overall 17.5) Australasia Europe FSU Middle East South NB: represents either hydrocarbon or total figures as reported by companies. In most cases these two metrics are similar in magnitude 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 68.9 tonnes of gas flared for every thousand tonnes of hydrocarbon produced in to 56.5 in. In Australasia the average has increased to 23.2 in compared to 14.5 in and 14.1 in, as the result of the introduction of data from operations or companies not included in previous years. 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 1.4 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 86% of water discharged was from offshore operations and 14% was from onshore operations. For every tonne of hydrocarbon produced in, 0.5 tonne of produced water was discharged and 0.9 tonne of produced water was re-injected. In, 0.6 tonne of produced water was discharged and 0.9 tonne was reinjected. The overall average oil content in produced water discharges was 13.4 mg/l, compared to 14.8 mg/l in and 15.8 mg/l in. Offshore the average oil content in produced water was 13.6 mg/l, whilst onshore it was 11.9 mg/l. (See Figure 4.1) Figure 4.1 Oil discharged per unit of produced water discharged milligrammes oil per litre of produced water discharged Onshore Offshore Overall 19

26 International Association of Oil & Gas Producers 4.1 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 4.1a), from a few kg per million tonnes in South and Europe, to 8 t/10 6 t in and Australasia, while offshore (Figure 4.1b) they vary from 5 t/10 6 t in to 19 t/10 6 t in Australasia. In the onshore average dropped from 11 t/10 6 t in to 3t/10 6 t in and 5t/10 6 t in ; the reduction since is partly due to the use of a more accurate measuring methodology for determining oil in water for key contributors of onshore discharges but also reflects reduced discharge volumes. Figure 4.1a: Oil discharged per unit of production onshore tonnes per million tonnes of hydrocarbon production (overall 3.0) Australasia Europe 0 FSU Middle East 0 South Figure 4.1b: Oil discharged per unit of production offshore tonnes per million tonnes of hydrocarbon production (overall 10.2) Australasia Europe FSU Middle East South The offshore average for the Australasia region shows a notable reduction over the 3-year period shown. This is the result of an increase in the reinjection of produced water in the region. 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 4.2 Quality (oil content) of produced water discharges Regional averages for the oil content of produced water discharged vary onshore from 0.3 to 45 mg/l (Figure 4.2a), while offshore they vary from 11 to 17 mg/l (Figure 4.2b). Figure 4.2a: Oil content of produced water discharged onshore milligrammes oil per litre of produced water discharged (equivalent to tonnes per million tonnes) (overall 11.9) Australasia Europe 1.2 FSU Middle East 0.3 South Figure 4.2b: Oil content of produced water discharged offshore milligrammes oil per litre of produced water discharged (equivalent to tonnes per million tonnes) (overall 13.6) Australasia Europe FSU Middle East South 21

28 International Association of Oil & Gas Producers 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. Onshore, where disposal to surface is often constrained by regulatory and environmental concerns, injection of produced water is the principal disposal route with 89% of water being returned below ground (see Figure 4.3a). In the n region, where 75% of onshore produced water was reinjected in, evaporation ponds are also used in some operations in desert areas, and large river basins are available in equatorial areas in which to discharge de-oiled produced water. Produced water reinjection in has risen notably compared to and as a result of the injection of increased volumes of produced water from declining oil fields in Gabon. Offshore (Figure 4.3.b), where de-oiled produced water can be discharged to sea with limited impact in the majority of locations, there is much less reinjection (average 29%). 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 25% of the offshore produced water was reinjected while in just 5% was reinjected. Figure 4.3a: Relative amounts of produced water re-injected to produced water discharged onshore by region expressed as percent total produced water generated 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Australasia Europe FSU Middle East South Overall Figure 4.3b: Relative amounts of produced water re-injected to produced water discharged offshore by region expressed as percent total produced water generated 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Australasia Europe FSU Middle East South Overall 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 & 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 to water-based muds. These challenges arise especially with techniques such as extended-reach and directional drilling, both of which may be required to develop many new reservoirs or to improve recovery from previously identified resources. OGP has proposed the following classification of NADFs: 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 (97% of the total reported) were discharged in all regions except the Middle East, and that discharges of cuttings with Group II fluids (3% of the total reported) only took place in and Europe. No discharges of cuttings with Group I fluids were reported in, nor were any discharges reported as Unspecified. 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. Environmental aspects of the use of non-aqueous drilling fluids associated with offshore oil & gas operations, Report 342, May