Environmental performance in the E&P industry 2008 data. Report No. 429 November 2009

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1 Environmental performance in the E&P industry data Report No. 429 November 29 I n t e r n a t i o n a l A s s o c i a t i o n o f O i l & G a s P r o d u c e r s

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 Environmental performance in the E&P industry data Report No: 429 November 29 Our overall aim is to ensure a consistent approach to training, management and best practice throughout the world. The oil & gas exploration and 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 and 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 Table of contents 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 DONG Eni E&P Division ExxonMobil GDF SUEZ (Formerly Gaz de France) Hess Corporation INPEX Kuwait Oil Company Maersk Marathon MOL Nexen Oil Search OMV Petrobras PetroCanada Petronas Premier PTT EP Qatar Petroleum Repsol YPF Shell Statoil Total Wintershall Executive summary... 1 Introduction... 4 review of submissions... 5 Detailed review: 1 Gaseous emissions Aqueous discharges Non-Aqueous Drilling Fluids (NADF) on cuttings Spills Energy consumption...27 Appendix A Tabulated data...29 Appendix B Glossary OGP i

4 Executive summary Over the past 1 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 activities carried out by contributing OGP member companies in. 32 member companies (5 more than last year), working in 62 countries worldwide, have submitted data for the report. Three companies are taking part for the first time, three companies that have contributed data in previous years but not in have returned to report data, and one company that reported last year did not take part this year. Information is aggregated at both global and regional levels and is expressed within 5 indicator categories: Gaseous emissions Aqueous discharges Non-aqueous drilling fluids (NADF) on cuttings Spills Energy consumption and flaring These data represent oil & gas wellhead production of 2,146 million tonnes (about 32% of global production sales in the BP Energy Review ). However, regional coverage is uneven, ranging from 98% of production in to 8% in the Former Soviet Union. Gaseous emissions In, OGP reporting companies emitted: 296 million tonnes of carbon dioxide ( ) equivalent to 141 tonnes of carbon dioxide per thousand tonnes of production 2.1 million tonnes of methane (CH 4 ) equivalent to 1. tonne of methane per thousand tonnes of production 1.1 million tonnes of non-methane volatile organic compounds (NMVOC) equivalent to.6 tonne of NMVOC per thousand tonnes of production 366 thousand tonnes of sulphur dioxide (SO 2 ) equivalent to.2 tonne of SO 2 per thousand tonnes of production 827 thousand tonnes of nitrogen oxides (NO X ) equivalent to.4 tonne of NO X per thousand tonnes of production Global average emission values (normalised to hydrocarbon production) for and CH 4 for were roughly flat at approximately.1% and 2% lower respectively than the results. Normalised NMVOC emissions were reduced ~16% versus based on individual companies efforts to reduce NMVOC emissions in some operations. NO X and SO 2 average emissions remain unchanged compared to those reported in. 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 and CH 4. OGP Report 414, OGP Publications: ii 1

5 Aqueous discharges Water from oil & gas production streams (produced water) is the most significant liquid discharge associated with E&P operations. For every tonne of hydrocarbon (oil, including condensates and gas) produced,.6 tonne of produced water was discharged and.9 tonne of produced water was reinjected. The quality of produced water discharges is measured in terms of oil content. In, the average concentration of oil in produced water was 13mg/l for onshore discharges and 15mg/l for offshore discharges. When expressed in terms of oil production, overall these discharges are equivalent to 9 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 7%. The average quantity of oil discharged per unit of production decreased by 12%. Non-aqueous drilling fluids (NADF) on cuttings Although most drilling fluids are water-based, some conditions demand the properties that are only available from non-aqueous drilling fluids (NADFs). 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, in reporting companies discharged 2,381 tonnes of NADF on drill cuttings, with 9% containing Group III base fluids. There were no reports of discharges of Group I fluids. Regional analysis shows that, in, Group III fluids were discharged in all regions except and the and that discharges of Group II fluids only took place in. In and the, no non-aqueous drilling fluids were reported discharged. Energy consumption and flaring Production of oil & 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 1.4 GigaJoules of energy for every tonne of hydrocarbon produced. This was 7% lower than the average. Data indicate that onshore production in was more energy intensive than offshore production. Regional analysis shows that operations in were the most energy intensive (2.8 GigaJoules per tonne of hydrocarbon produced), while the was the least energy intensive (.5 GigaJoules per tonne). This is partly due to lower levels of processing of reservoir fluids (oil, gas and water). Flaring is the controlled burning of natural gas produced in the course of oil & gas 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, 18.6 tonnes of gas was flared for every thousand tonnes of hydrocarbon produced versus 2.2 in and 23.9 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. These reductions in flaring rates translate to reductions in and other gaseous emission rates. Spills A spill is defined as any loss of containment that reaches the environment, irrespective of quantity recovered. In, participating OGP member companies reported 2,978 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 1.6. The reported spills >1 bbl resulted in the release of a total of 18,266 tonnes of oil. The average quantity of oil spilled per unit of hydrocarbon production has risen to 9 tonnes per million tonnes production, an increase of 25% compared to and 14% compared to. There is significantly less oil spilled offshore than onshore. Spill volumes are usually dominated by few incidents. In, the largest reported oil spill volume resulted from a single incident that occurred in Angola where 2,781 tonnes of oil (13% of the total) were spilled as a result of equipment failure during tanker loading. 6% (169 tonnes) of the material spilled in that incident was recovered. Regional analysis shows that the average size of onshore spills is higher in than in any other region. This can be mainly 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. Definitions of Group I, II and III base fluids are provided in section

6 Introduction review of submissions Over the past 1 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 project 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 and to demonstrate the industry s wish for greater transparency concerning its activities. This will help them to identify better and more efficient ways of operating. Environmental information relating to emissions and discharges is collected under the following five categories: Emissions to air Aqueous discharges Discharges of non-aqueous drilling fluids on cuttings Accidental spillages of oil and chemicals Energy efficiency and flaring 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 23, 24, 25, and and summary reports for activities in 21 and 22 have been published previously. 32 OGP member companies reported environmental information for, on average, 7 countries each. Data from 62 countries are represented in the report. The data represent 2,146 million tonnes of hydrocarbon production, approximately equivalent to 32% 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 & 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 Production figures in this report include oil & 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 where a high percentage of hydrocarbon production is represented the information can be taken to approximate industry performance. In, the, & and, the data give a broad indication of industry performance. For the former Soviet Union (), data reported by participating companies represents just 8% 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 has been too low to be considered representative for the region. In however the production reported for the region has reached 2% of known production and thus results for the are coloured in the graphs and included in the cross-regional comparisons, while pre- results are shown as grey bars in the graphs. Global averages are calculated using data from all regions, including those from the and the 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, 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, energy) and hydrocarbon production data are available. Because some companies did not submit data for OGP report 359, 372, 383, 399, 414, 339s & 347s, OGP Publications: 4 5

7 all metrics covered in the survey, some of the analyses will cover less than 1% of the total production reported. Coverage for the analyses is presented below. Percentage of reported production included in normalised analyses Gas emissions per unit of production All regions 1% 1% 1% 98% 86% 1% 1% 98% CH 4 1% 92% 1% 1% 86% 1% 1% 97% NMVOC 97% 8% 98% 1% 84% 94% 1% 93% SO 2 97% 8% 98% 1% 84% 94% 1% 93% NO X 97% 8% 98% 1% 84% 94% 1% 93% Oil discharged in produced water per unit of production 95% 97% 92% 88% 34% 92% 92% 84% Oil spilt per unit of production 99% 94% 97% 1% 94% 99% 99% 97% Energy consumed per unit of production 98% 97% 98% 1% 86% 97% 1% 96% In the subsequent figures in this section, we show overall aggregated information for the years 22 to. Data for the earlier years have already been published but are included in this report for ease of comparison. 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. Gaseous emissions In, gaseous emissions were as follows: 296 million tonnes of carbon dioxide ( ) equivalent to 141 tonnes of carbon dioxide per thousand tonnes of production; 2.1 million tonnes of methane (CH 4 ) equivalent to 1. tonne of methane per thousand tonnes of production; 1.1 million tonnes of non-methane volatile organic compounds (NMVOC) equivalent to.6 tonne of NMVOC per thousand tonnes of production; 366 thousand tonnes of sulphur dioxide (SO 2 ) equivalent to.2 tonne of SO 2 per thousand tonnes of production; and 827 thousand tonnes of nitrogen oxides (NO X ) equivalent to.4 tonne of NO X per thousand tonnes of production. These normalised figures (tonnes of gas emitted per thousand tonnes of production) are broadly consistent with data published for activities from Emissions per thousand tonnes hydrocarbon production tonnes per thousand tonnes CH 4 1. Aqueous discharges NMVOC.6 SO 2.2 NO X GHG 162 GHG: Total GreenHouse Gases ( + CH 4 expressed in equivalent) Aqueous discharge covers the discharge of produced water, mainly produced formation water. The quality of produced water discharges is usually monitored by the measurement of its oil content. The overall average oil content in produced water discharges was 14.8mg/l, compared to 15.8mg/l in and 16.4mg/l in. the average oil content in produced water was 14.8mg/l, whilst onshore it was 13.1mg/l. For every tonne of hydrocarbon (oil & gas) produced in,.6 tonne of produced water was discharged and.9 tonne of produced water was reinjected. In,.6 tonne of produced water was discharged and 1. tonne was reinjected. Oil discharged per unit of produced water discharged milligrammes oil per litre of produced water discharged Oil spills: For every million tonnes of hydrocarbons produced, some 8.7 tonnes of oil were spilt, compared to 6.9 tonnes in and 7.6 tonnes in. The reported spillage rate onshore was 6 times the offshore average. 6 7

8 Oil spilt per unit of hydrocarbon production tonnes per million tonnes Energy consumption: On average, 1.4 GigaJoules of energy was required (1.5 GigaJoules in and 1.5 GigaJoules in ) for every tonne of hydrocarbon production. Where a breakdown is available (~8% of reported energy), energy requirements were largely met by combustion of fuels on-site rather than by purchase of electricity or steam. Energy consumed per unit of hydrocarbon production GigaJoules per tonne energy Purchased energy On-site combustion 9 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). Nonroutine and emergency emissions can arise from well testing and emergency flaring and gas venting. Gaseous emissions covered in this report are those considered most relevant from a process control as well as from a regulatory perspective. They are: carbon dioxide ( ), methane (CH 4 ), non-methane volatile organic compounds (NMVOC), sulphur dioxide (SO 2 ) and nitrogen oxides (NO X ), and separately, greenhouse gases ( + CH 4 expressed as 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, to estimate the emissions from different sources, care must be taken when comparing aggregated numbers from different regions and different years. The following sub-sections present the data in terms of regional mean values for emission normalised by unit of production for the years, and. The use of normalised ratios (emission per unit of production) facilitates comparisons between different operating regions while absolute emission loads give a sense of the scale of the emissions. 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 See for example: Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions (23), joint OGP/API/IPIECA report, 23 Compendium of Greenhouse Gas Emission Estimation Methodologies for the Oil & Gas Industry, API, 24 Sangea Energy and Emissions Estimating System, API, 8 9

9 1.1 Carbon Dioxide ( ) 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 the gas 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 Regional averages for quantity of carbon dioxide emissions per unit of production vary from 7 to 233 tonnes of carbon dioxide per thousand tonnes of hydrocarbon production, as shown in Figure In the range was between 71 and 254 tonnes per thousand tonnes of production. 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 Regional averages for methane emissions expressed per unit of production vary from.2 to 1.8 tonnes of methane per thousand tonnes of hydrocarbon production, as shown in Figure In the range was between.2 and 1.6 tonnes per thousand tonnes of production. Figure 1.1.1: emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Figure 1.2.1: CH 4 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production 3 (overall 141) (overall 1.) (overall 141) (overall 142) (overall 1.) (overall 1.) The higher normalised carbon dioxide emissions in result from more widespread flaring of associated gas than in other parts of the world. In much of, limited infrastructure currently exists to market and use the gas associated with the production of oil. However, emission rates in are declining due to recent projects developed to improve the infrastructure. By contrast, in there are mature gas markets and infrastructure. Consequently, emission rates are lower Emissions by activity Just 39% of the total emissions reported were categorised by activity. Where the activity was specified, almost all of the carbon dioxide emissions reported (95%) are from process and treatment activities. Drilling activities account for 4% of total carbon dioxide emissions reported and 1% are attributable to activities carried out within terminals. Emissions intensity for and the are lower than for other regions. In 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 Emissions by activity The activity was specified for just 37% of the total CH 4 emissions reported. Where the activity is specified, the largest portion of methane emissions, 97%, is from process and treatment. Terminal and drilling activities are responsible for the remaining 3% of total methane emissions reported. GHG: Total Greenhouse Gases ( + CH 4 expressed as equivalent) 1 11

10 1.3 Greenhouse Gas (GHG ) emissions For E&P activities, and CH 4 are the principal contributors to greenhouse gas emissions, with other gases such as N 2 O playing a minor role. The and CH 4 data presented above are used to calculate an estimate of GHG emissions for the contributing OGP reporting companies, using standard conversion to equivalent (GHG = + 21 x CH 4 ) Emissions per unit of production Regional averages for quantity of greenhouse gas emissions per unit of production vary from 74 to 262 tonnes of greenhouse gas per thousand tonnes of hydrocarbon production, as shown in Figure In the range was between 76 and 287 tonnes per thousand tonnes of production. 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 Regional averages for quantity of NMVOC emitted per unit of production vary from.3 to.9 tonnes per thousand tonnes of hydrocarbon production, as shown in Figure In the range was between.3 and 1.2 tonnes per thousand tonnes of production. Figure 1.3.1: GHG emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Figure 1.4.1: NMVOC emissions per unit of production tonnes per thousand tonnes of hydrocarbon production (overall 162) (overall 162) 2. (overall.58) (overall.68) 2 25 (overall 163) (overall.7) GHG: Total GreenHouse Gases ( + CH 4 expressed in equivalent) Emissions by activity Just 39% of the total greenhouse gas emissions reported were categorised by activity. Where the activity was specified, almost all of the greenhouse gas emissions reported (96%) were from process and treatment activities. Drilling activities account for 3% of total greenhouse gas emissions reported and 1% are attributable to activities carried out within terminals. NMVOC emissions are highest in (.9 tonnes of NMVOC per thousand tonnes of production). The second highest region is with a rate of.8 tonne of NMVOC per thousand tonnes of production. The high intensity is the result of high flaring rates that produce higher quantities of unburned NMVOCs. has the lowest normalised emissions, producing.3 tonne of NMVOC per thousand tonnes production. This is due, in part, to relatively little flaring, as well as to stringent regulatory controls that limit NMVOC emissions Emissions by activity The activity was specified for 38% of the total NMVOC emissions reported. Where the activity is specified, the largest proportion of emissions of NMVOC (9%) comes from processing and treatment. Terminal activities are responsible for 9%, and drilling the remaining 1% of total NMVOC emissions reported

11 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 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 high concentrations of H 2 S Emissions per unit of production Regional averages for quantity of SO 2 emissions expressed per unit of production vary from.3 to.76 tonne per thousand tonnes of hydrocarbon production, as shown in Figure In the range was between.4 and.16 tonne per thousand tonnes of production ( results excluded in see review of submissions section). Figure 1.5.1: SO 2 emissions per unit of production tonnes per thousand tonnes of hydrocarbon production Nitrogen oxides Emissions of nitrogen oxides, (principally nitric oxide and nitrogen dioxide, expressed as NO X ), occur almost exclusively from the combustion of 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 Regional averages for quantity of NO X emitted per unit of production vary from.1 to.8 tonne of NO X per thousand tonnes of hydrocarbon production, as shown in Figure In the range was between.2 and.7 tonne per thousand tonnes of production. Figure 1.6.1: NO X emissions per unit of production tonnes per thousand tonnes of hydrocarbon production.8.7 (overall.41) (overall.41) (overall.18) (overall.18) (overall.38).4.12 (overall.2) Asia.4 and have the lowest average normalised emissions of SO 2,.3 and.4 tonne per thousand tonnes of hydrocarbon production respectively Emissions by activity The activity was reported for 45% of the total SO 2 emissions. Where the activity is specified, the largest percentage of SO 2 emissions, 92%, relate to processing and treatment. The drilling category represents 6% of total SO 2 emissions reported and the terminal activity represents the remaining 2%..1. Normalised NO X emissions are highest in the and n regions, each showing an average of.8 and.7 tonne of NO X per thousand tonnes of hydrocarbon production respectively. The region has the lowest normalised NO X emissions of.1 tonne NO X per thousand tonnes of hydrocarbon production Emissions by activity The activity was reported for 38% of the total NO X emissions reported. Where the activity is specified, the largest percentage of NO X emissions (78%) are from process and treatment activities. Drilling accounts for 21% and the terminal category represents 1% of total NO X emissions reported

12 2 Aqueous discharges Produced water is the highest volume liquid discharge generated during the production of oil & 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 rivers, lakes, seas, 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 & 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 region 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. These differences in analytical methodologies make the direct comparison of aggregated data difficult

13 2.1 Quality (oil content) of produced water discharges Figure 2.1.a: Oil content of produced water discharged onshore milligrammes oil per litre of produced water discharged (equivalent to tonnes per million tonnes) (overall 13.1) (overall 17.6) (overall 7.9) 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 87% of water being returned below ground. In contrast, in the n region where 36% of onshore produced water was reinjected, there is widespread use of evaporation ponds in desert areas, and large river basins are available in equatorial areas in which to discharge de-oiled produced water., where the majority of de-oiled produced water can be discharged to sea with limited impact, there is much less reinjection (average 17%). 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 the, 84% of the offshore produced water was reinjected while in just 5% was reinjected Figure 2.2.a: Relative amounts of produced water re-injected to produced water discharged onshore by region expressed as percent total produced water generated.4 no data 1 discharged reinjected Figure 2.1.b: Oil content of produced water discharged offshore milligrammes oil per litre of produced water discharged (equivalent to tonnes per million tonnes) 8 4 (overall 14.8) 6 (overall 15.4) 3 (overall 17.4) Regional averages for the oil content of produced water discharged vary onshore from.4 to 99mg/l, while offshore they vary from 1 to 28mg/l. For onshore discharges, the drop in concentration for an discharges in was largely influenced by reporting from new participating companies. 2 Figure 2.2.b: Relative amounts of produced water re-injected to produced water discharged offshore by region expressed as percent total produced water generated 1 8 discharged reinjected

14 3 Non-Aqueous Drilling Fluids (NADF) on cuttings 2.3 Quantity of oil discharged in produced water per unit of production Figure 2.3.a: Oil discharged per unit of production onshore tonnes per million tonnes of hydrocarbon production Figure 2.3.b: Oil discharged per unit of production offshore tonnes per million tonnes of hydrocarbon production 8.2 (overall 3.8) (overall 5.8) (overall 2.1) 3 (overall 11.1) (overall 12.2) (overall 13.4) Regional averages for the quantity of oil discharged by unit of production of hydrocarbons vary, onshore, from a few kg per million tonnes in to 8t/1 6 t in, while offshore they vary from 2t/1 6 t in the to 23t/1 6 t in. In the onshore average dropped from 11t/1 6 t in to 3t/1 6 t in ; this is partly due to the use of a more accurate measuring methodology for determining oil in water for key contributors of onshore discharge. 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 General While most drilling in the offshore oil & gas industry is achieved using water-based drilling fluids (muds), technical challenges often require the use of drilling fluids that provide higher lubricity, stability at higher temperatures and well-bore stability non-aqueous drilling fluids (NADF). These challenges arise especially with new 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. >.35 Group II Low toxicity mineral oil Group III Enhanced mineral oil Synthetics (esters, olefins, paraffins) <.5 <.1 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 posed minimal threat to the marine environment. Non-aqueous drilling fluids (NADF) contain more than 3% non-aqueous base fluid (NABF) as a continuous phase (typically 5%-8% 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. 3.2 Non-Aqueous Base Fluid Discharged on Cuttings The following chart, Figure 3.1, 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 (13) 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. Figure 3.1: Total base fluid (NADF) discharges to sea, by region; 25 tonnes NADF NADF Group III NADF Group II Note: No Group 1 NADF discharges were reported in -; NDAF discharges were only reported by 13 companies in - 2 Environmental aspects of the use of non-aqueous drilling fluids associated with offshore oil & gas operations, Report 342, May

15 4 Spills Spills are an important environmental performance indicator for the oil & gas industry since they can have a significant and visible impact on the environment. The degree of environmental impact is highly dependent on the nature of the release, where it occurred and how it was subsequently managed. Oil exploration and production companies have spill contingency plans and measures in place to respond to and mitigate spills. The majority of spills in the oil & gas E&P 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. Oil Spills In, companies reported a total of 5,7 spills. Of these, 2,722 (48%) were spills of less than one barrel in volume, amounting to a cumulative volume of 83 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. 83% of the reported oil spills occurred onshore and 6% offshore. The location was not specified for the remaining 11%. In, 2,978 oil spills greater than 1 bbl in size were reported. Figure 4.1 shows the number of spills normalised per unit hydrocarbon production. The normalised rate for was 1.4 spills per million tonnes of production versus rates of 1.6 and 1.8 for and respectively. Figure 4.1: Number of oil spills > 1 bbl per million tonnes of hydrocarbon production (overall 1.4) (overall 1.6) (overall 1.8) With regard to oil spill volumes, oil spills greater than 1 bbl in size reported for resulted in the release of a total of 18,266 tonnes of oil. When normalised to hydrocarbon production, spill volume rates have risen from 7.6 tonnes per million tonnes of production in and 6.9 in to 8.7 in, an increase of 14% on levels and 25% on levels. Spill volumes are usually dominated by a few incidents. In, 13% of the total spill volume resulted from a single incident that occurred in Angola where 2,781 tonnes of oil were spilled. The accident occurred as a result of equipment failure (not linked to corrosion) during tanker loading. 6% of the material spilled in that incident was recovered. The quantity of oil spilled per unit of hydrocarbon production for each region is shown in Figure

16 Figure 4.2: Quantity of oil spilled (spills > 1 bbl) per unit of hydrocarbon production by region tonnes per million tonnes 3 (overall 8.7) (overall 6.9) (overall 7.6) Figure 4.4: Quantity of oil spilled (spills > 1 bbl) per unit of hydrocarbon production offshore by region tonnes per million tonnes (overall 3.) (overall 4.) (overall.4) Figures 4.3 and 4.4 show the reported quantities of oil spilled per unit of hydrocarbon production, onshore and offshore respectively, in the different geographic regions. the increases in the quantity of oil spilled per unit of production in both and are due to an increased number of spills in Argentina and Nigeria. the quantity of oil spilled per unit of production in has increased from.5 in and 1. in to 12.7 in. This figure is influenced by a single crude oil spill in Angola as described above. Spill volumes in for were similarly affected by a single large oil spill in Norway. Figure 4.3: Quantity of oil spilled (spills > 1 bbl) per unit of hydrocarbon production onshore by region tonnes per million tonnes (overall 18.5) (overall 1.9) (overall 17.3) Figure 4.5 shows the distribution of spills larger than 1 barrel in terms of number of spills in each size category. In terms of number of events, the distribution is dominated by the large number of spills between 1 and 1 barrels in size. However, it is clear that the quantity released overall (for those spills where a size category was specified) will be dominated by a few relatively large events. In addition to the data shown in Figure 4.5, a total of 2,722 (1,766 onshore, 853 offshore, and 13 unspecified location) of less than 1 barrel were reported by participating companies. The cause was given for 27 of the 44 (32 onshore, 11 offshore, 1 unspecified location) reported incidents in which more than 1 barrels of oil was spilled. These 27 cases were associated with 26% of the total oil spilled. 1 of those incidents (17% of the total oil spilled ) were caused by equipment failure excluding corrosion. A further 7 of the incidents (5% of the oil spilled) were caused by corrosion, 5 (1%) by operator or technical error, 2 (2%) by third party damage, 2 (1%) by hurricane damage and 1 by a road transport vehicle incident (.2%). Figure 4.5: Distribution of oil spills onshore and offshore by size number of spills , < x < 1 bbl < x < 1 bbl > 1 bbl Excluding spills <1bbl in size 25

17 5 Energy consumption and flaring 5.1 Energy consumption The energy used to produce oil & 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 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 many oilfields the energy is derived from locally produced gas used as fuel in turbines to produce electricity and drive compressors. Where supply of produced gas is limited, additional energy in the form of electricity or heat (steam) may be purchased from external suppliers. On the basis of the data reported, energy produced on site is the dominant source of power. No source was specified for 17% of the total; of the remaining 83%, 76% was produced on-site and 7% was purchased. In, OGP reporting companies consumed on average 1.4 GigaJoules of energy for every tonne of hydrocarbon produced. This is a 7% reduction compared to the average and is influenced by new reporting of energy and production data by companies operating in the region. Data indicate that onshore production in was more energy intensive than offshore production. Figure 5.1: Energy consumption per unit of hydrocarbon production by region GigaJoules per tonne (overall 1.4) (overall 1.5) (overall 1.5) In Figure 5.1 the (overall) energy consumption is normalised against the quantity of hydrocarbons produced for each region. This shows a fairly narrow range of values with an average of 1.4 GJ/t. There are approximately 42.8GJ of energy in one tonne of diesel oil equivalent

18 Appendix A Data tables 5.2 Flaring Flaring is the controlled burning of natural gas produced in the course of oil & gas exploration and production 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. Figure 5.2 shows the flaring per unit of hydrocarbon production as reported by the participating companies by region. In, 18.6 tonnes of gas was flared for every thousand tonnes of hydrocarbon produced versus 2.2 in and 23.9 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. Intensities are higher in the region where there is limited gas sales infrastructure. Projects improving the infrastructure in have helped reduce flare from 74.2 tonnes of gas flared for every thousand tonnes of hydrocarbon produced in to 6.2 in. Figure 5.2: Flaring per unit of hydrocarbon production by region Tonnes per thousand tonnes (overall 18.6) (overall 2.2) (overall 23.9) NB: represents either hydrocarbon or total figures as reported by companies. In most cases these two metrics are similar in magnitude The following tables provide the data from which the figures and charts throughout the report are compiled. Summary Production associated with database and BP Statistical Review of World Energy by region Region Production in this report (1 6 t) BP Review production (1 6 t) Production as % of BP Review production Equivalent last year % 61% % 42% % 13% 115 1,349 8% 8% 325 1,597 2% 15% 37 1,359 23% 25% % 41% Total 2,146 6,697 32% 32% NB: Production figures given in this report relate to gross production whereas world data extracted from the BP Statistical Review represent net production. Thus the data are not directly comparable, but the percentage of world production figures are given as indicative of the relative regional contributions in the database. No. of useable company/country data sheets/sets by region Region No. of data sheets No. of data sets No. of data sheets No. of data sets No. of data sheets No. of data sets Total Data sheet: all data for one country for an individual company Data set: a set of data with distinct company, country and location (onshore/offshore/unspecified) where there is a positive return of production, emissions, discharges, energy or spills data Gas emissions per unit of hydrocarbon production Emission per 1 3 t production (t/1 3 t) Hydrocarbon production 1 6 t Emission per 1 3 t production (t/1 3 t) Hydrocarbon production 1 6 t Emission per 1 3 t production (t/1 3 t) Hydrocarbon production 1 6 t , , ,44 CH , , ,44 NMVOC.58 1, ,4.7 1,997 SO , ,6.2 1,992 NO X.41 1, ,7.38 2,4 GHG NB Data only included where gas quantity and production level are both reported GHG: Total greenhouse gases ( + CH 4 expressed in equivalent: GHG = + 21 x CH 4 ) 28 29

19 Oil discharged with produced water per unit of produced water Oil discharged per unit PW (mg/l) Oil discharged per unit PW (mg/l) Oil discharged per unit PW (mg/l) NB Data only included where oil in produced water and produced water quantity are both reported Oil spilt per unit of hydrocarbon production Oil spilt per 1 6 t production (t/1 6 t) Hydrocarbon production 1 6 t Oil spilt per 1 6 t production (t/1 6 t) Hydrocarbon production 1 6 t Oil spilt per 1 6 t production (t/1 6 t) Hydrocarbon production 1 6 t , ,5.5 1, , , ,974 NB Data only included where quantity of oil spilt and production level are both reported. Excludes spills <1bbl in size Total oil discharged (discharges + spills) per unit of hydrocarbon production Total oil discharged per 1 6 t production (t/1 6 t) Hydrocarbon production 1 6 t Total oil discharged per 1 6 t production (t/1 6 t) Hydrocarbon production 1 6 t Total oil discharged per 1 6 t production (t/1 6 t) Hydrocarbon production 1 6 t , , , , ,6 1 Gaseous Emissions Gross emissions of gases per region (1 6 t) CH 4 (1 3 t) ,97.5 NMVOC (1 3 t) ,145.7 SO 2 (1 3 t) NO X (1 3 t) GHG (1 6 t) (1 6 t) CH 4 (1 3 t) ,139.4 NMVOC (1 3 t) ,355.3 SO 2 (1 3 t) NO X (1 3 t) GHG (1 6 t) (1 6 t) CH 4 (1 3 t) ,38.8 NMVOC (1 3 t) ,392.3 SO 2 (1 3 t) NO X (1 3 t) GHG (1 6 t) NB For onshore, offshore and overall results data are only included where oil in produced water and spills are reported as well as production levels for the dataset. Energy consumption per unit of hydrocarbon production % Onsite combustion % Purchased % Total energy consumption (GJ/t) Production (1 6 t) 2,64 1,921 1,919 1,913 1,967 NB Data only included where energy consumption and production level are both reported GHG: Total greenhouse gases ( + CH 4 expressed in equivalent: GHG = + 21 x CH 4 ) GHG: Total greenhouse gases ( + CH 4 expressed in equivalent: GHG = + 21 x CH 4 ) 3 31