Oil & Gas Emissions Seminar. Overview of Environmental Regulatory Requirements in the Oil and Gas Industry. Lynn Hunter, TUV NEL.

Transcription

1 Overview of Environmental Regulatory Requirements in the Oil and Gas Industry Lynn Hunter, TUV NEL 11^ June 2008

2 ,., ^. Oil & Gas Emissions Seminar ' '- Overview of Environmental Regulatory Requirements in the Oil and Gas Industry Lynn Hunter, TUV NEL Ltd 1 INTRODUCTION As the focus on environmental pollufion, global warming and climate change increases, greater demands are being placed on the need to reduce and control harmful atmospheric emissions. In recent years, this has resulted in the oil and gas industry, along with other energy intensive sectors, having to drastically adapt the way in which they manage and report emissions in order to comply with growing legislative requirements. This paper provides an interpretafion of the key environmental legislafion applicable to the offshore oil and gas sector. This includes the EU Emissions Trading Scheme (ETS) implemented under EU Directive 2003/87/EC [1] and the Integrated Pollufion Prevention and Control Directive (IPPC) [2]. Although these controls have now been in place for a number of years, recent expansions to both schemes has had a major impact on the offshore sector. The main source of atmospheric emissions in the offshore oil and gas sector is combustion emissions. These fail into 2 main categories; fuel emissions generated from combusfion plant used for power generation and flaring emissions, produced from burning off waste gases in flare stacks. The EU ETS covers carbon dioxide (CO2) emissions released from fuel combustion plant and flare stacks and the IPPC Directive covers all other significant emissions from fuel combustion plant. 2 EU ETS 2.1 Background The EU ETS essentially provides a European-wide cap and trade scheme to help member states achieve their legally binding greenhouse gas (GHG) reduction targets under the Kyoto Protocol. Phase 1 of the Scheme, treated as the trial period, ran from 1 January 2005 to 31 December This phase effectively prepared member states and permit holders for inclusion into Phase 2. v.'hich was timed to coincide with the Kyoto Protocol commitment period. Phase 2 runs from 1 January 2008 to 31 December A third phase, currenfiy at negotiation stage, is expected to bring with it significant changes. Including carbon capture and storage. UK offshore oil and gas installations are regulated by the Department of Business, Enterprise and Regulatory Reform (DBERR). The scheme is controlled by 'ihe issue of GHG permits. At the start of each phase operators are allocated with emission allowances which can be bought or sold accordingly at the end of each reporting period to other participants in the scheme. The number of allowances allocated to each installation is set down in a document called the National Allocation Plan (NAP). At the initial stages the operator is required to submit for approval a monitoring and reporting plan (MRP) which outlines their proposed methodology for quantifying the total emissions from the installation. Thereafter, the operator submits an annual report to the regulator specifying the total amount of emissions dispensed over the reporting period. The report is subject to verification by an approved verification body appointed by the permit holder. The United Kingdom Accreditation Service (UKAS) is responsible for approving EU ETS verification bodies in the UK. The Scheme ultimately allows an overall ceiling on the amount of CO2 emissions to be established whilst at the same fime providing a financial incentive for operators to reduce their CO2 emissions through improvements in energy efficiency.

3 The workings and overall success of the EU ETS naturally rely on the accurate measurement and determinafion of CG2 emissions. This is not only vital to provide transparency in the scheme to reduce financial exposure to stakeholders, but more importantiy, to ensure credible environmental data is acquired to allow environmental impact assessments. Commission Decision of 18A/II/2007 [3] was infroduced to set down guidelines for monitoring and reporting greenhouse gas emissions to provide confinuity between member states. These Guidelines, a revision of the Phase 1 guidelines, are generally referred to as MRG2007 or MRG2. One of the most significant changes in Phase 2 is the inclusion of offshore flaring, which had been exempt from Phase 1 due to the perceived technical difficulfies in achieving the sfilct measurement targets. 2.2 EU ETS Monitoring and Reporting Requirements In some respects the revised guidelines under MRG2007 have become more relaxed. For example, in recognition of the technical difficulties involved with flaring the associated measurement uncertainty targets have been reduced since Phase 1. However, overall they have t>ecome a lot more prescriptive and demanding in terms of the required measurement regimes and reporting methodologies. This is more so the case for the larger emitters under categories B and C. Around 90% of UK offshore installations are grouped under Category B, whereby emitting between 50 and 500 ktonnes of CO2 per annum. As can be seen in Figure 1. there are very few offshore instailafions that fall below (Category A) and above (Category C) this level. Total no. of installations = 89 CATEGORY B (> 50 s 500 ktonnes of CO; per annum) 90% g^ 2% CATEGORY C > 500 ktonnes of CO2 per annum CATEGORY A ( 50 ktonnes of CO? per annum) Figure 1 - Breakdown of UK EU ETS offshore sector installations Monitoring {Methodologies Operators can choose different methodologies for monitoring their CO2 emissions. They can either opt for a calculation based methodology or a measurement based methodology, or a combination of both.

4 Measurement Based Methodology Measurement based methodologies relate to the use of Continual Emissions Measurement Systems (CEMS), often referred to as Automated Measurement Systems (AMS). These systems are used for the continuous and automated measurement of flue gas emissions. This can either involve in-situ methods, where the measurement devices are located in the flue, or extractive methods, v^rtiere the flue gas emissions are automatically extracted and analysed by a measurement system located close by the stack. Periodic sampling of gases using a CEMS system does not qualify in the Guidelines as a measurement based methodology. There appears to be a lack of confidence in the use of CEMS for EU ETS reporting. This is reflected in MRG2007, where in order to use CEMS it must be demonstrated that the system is as accurate as the calculation method. In addition, the European Commission must also be informed where CEMS is used. Although MRG2007 does not sfipulate the reason for this stance, it is understood to be due to the fact that CEMS currentiy on the market do not meet the fight measurement uncertainty levels required in the Guidelines. For this reason the offshore sector use calculafion based methodologies to determine their emissions. Even if a CEMS was demonstrated as suitable and accurate for EU ETS reporting purposes, it is clearly unsuitable for certain applications, such as flaring. As the titie suggests, CEMS is designed to measure emissions. However, in a flare stack there are no captured emissions to measure. Unlike other intemal combusfion plant, such as gas turbines and diesel engines, in a flare stack there is no flue or duct after the combustion stage in which to contain and direct the emissions. Combustion takes place as the gases exit the top of the flare stack, where thereafter the emissions are openly dispersed into the atmosphere- Calculation Based Methodology The calculation based methodology uses three main variables to calculate emissions. Activity Data Activity data for combustion activities generally refers to the amount of fuel consumed during the process. Dependent on the requirements, this may involve metering the fuel use or estimations based on material purchase and stock records Emission Factor (E.F) The emission factor is a measure of the fuels cartjon content Oxidation Factor The oxidation factor for combustion represents the proportion of carbon not oxidised or converted during the combustion process. For example a factor of '1' assumes a fully efficient combusfion process where all carbon is oxidised and converted into CO2. Using these 3 factors, the total emissions over the reporting period Is derived from the following calculation: CO2 Emissions = Activity Data " Emission Factor * Oxidafion Factor

5 Source Streams The Guidelines allow operators to group different emission sources (physical point of emissions) together to allow them to be categorised as major, minor or de minimis streams. Where necessary, some source streams may be treated less crifical than others. For instance. minor and de minimis source streams may, where justified, be subject to less comprehensive and stringent monitoring requirements than major source streams. This approach allows the operator some flexibility when controlling emissions from Uie installation. The criterion for each source stream group is outlined below. De minimis Source Streams - A group of minor source streams selected by the operator and jointiy emitting 1 ktonnes of fossil C02 or less per year or that contribute less than 2% (up to a maximum contribution of 20 ktonnes of fossil CO2 per year) of total annual emissions of fossil CO2 of that installation before subtraction of transferred CO?, whichever is the highest in terms of absolute emissions. Minor Source Streams - Those source streams selected by the operator to joinfiy emit 5 ktonnes of fossil C02 or less per year or to contribute less than 10% (up to a total maximum contribution of 100 ktonnes of fossil CO2 per year), to the total annual emissions of fossil CO2 of an installation before subtraction of transferred CO2, whichever is the highest in tenns of absolute emissions. Major Source Streams - A group of source sfreams which do not belong to the group of 'minor source streams'. Tier of Approaches The calculafion based methodology utilises a fiered approach system which sets higher tier levels for the larger emitter (Tier 1 being the lowest tier). The higher the tier, the more comprehensive and demanding the monitoring and reporting requirements are. This approach attempts to acquire more accurate data for the larger emitters; recognising that the risk and consequences of inaccurate reporting from the larger emitters would have a much greater environmental impact. The activity data, emission factor and oxidation factor, are all assigned with their own set of reporting tiers. The Guidelines describes a hierarchy for complying with the tier of approaches. Category B and C installations are required to apply the highest tier to each reporting variable (i.e. activity data, emissions factor, oxidation factor) for all source streams (major, minor and de minimis) when calculating emissions. However, where this is demonstrated to be technically unfeasible or will lead to unreasonably high costs, then the next lower tier may be used for that variable. The Guidelines set a minimum tier level for each installation category which should be met for all major source streams unless demonstrated as technically unfeasible. Subject to approval by the competent authority, the operator may select, as a minimum, Tier 1 for the variables used to calculate minor source sfreams and apply a no-tier estimation for de minimis source streams.

6 Activity Data Tiers The tier level assigned to activity data sets the maximum permitted measurements uncertainty on the reported data. Different levels have been set for fuel emissions and fiaring emissions. These are outlined t)elow in Table 1... Table 1 - Activity Data Tiers (showing minimum tier for each installation category) Combustion Emissions Tierl Tier 2 Tiers Tier 4 Minimum tier for each installation category (for major source streams) Fuel ± 7.5% ±5% ± 2.5% ±1.5% A = Tier 2, B = Tier 3, C = Tier 4 Flaring % ± 12.5% ± 7.5% N/A A = Tier 1, B = Tier 2, C = Tier 3 Fuel used in combusfion plant can either be gaseous or liquid fuel. For liquid fuels DBERR has implemented the highest Tier 4 requirement for major source streams and a Tier 3 requirement for minor source streams. For gaseous fuels a Tier 4 target has been set for Category C instailafions (unless this is not technically feasible or would lead to unreasonable high costs) with a Tier 3 target set for Category B installafions. Due to the technical difflculties involved in monitoring emissions from flares, DBERR has recognised that for 2008 the majority of offshore instailafions, which are Category B, will not meet the highest requirements set under Tier 3 or the Category B requirements under Tier 2. Therefore, for all offshore installafions, a Tier 1 target has been permitted during 2008 with a Tier 2 target set for In addition to metering fuel consumption, the use of process modeling and valve position metering has been accepted for the purpose of deriving activity data, where it is recognised that there can be difficulties in sourcing meters that operate accurately over the full range. Emission Factor Tiers The emission factor tier levels describe different approaches to be used for determining the emission factor (EF). For fuel emissions, It is also necessary to determine the net calorific value (NCV) of the fuel, which is also subject to different tiered approaches. Tier 1 involves the use of standard reference factors and Tier 2 entails the use of more country-specific factors or installation specific factors derived from measuring or modeling fuel parameters. Tier 3 comprises the most accurate and comprehensive approaches for determining emissions factors and net caloriflc values. This involves the sampling of specific fuel types in accordance with Section 13, Annex 1, of the Guidelines, using where possible accredited test laboratories, traceable test equipment and recognised standards and methods. The tiers covering the emission factor and net calorific value relating to fuel emissions and flaring emissions are summarised below in Tables 2 and 3.

7 Table 2 - Emission Factor and NCV Tiers - Fuel Emissions Tierl MRG Section 11 Annex 1 reference factors (EF & NCV) Tier 2a UNFCCC country specific factors (EF & NCV) Tier 2b NCV for commercially traded fuels from purchasing records, EF from density measurements Tiers Activity specific factors in accordance with MRG Section 13, Annex 1 (EF & NCV) Minimum tier for each installation category (for major source streams) A, 8 & C = Tier 2a/b ' Table 3 - Emission Factor Tiers - Flare Emissions Tierl. Reference E.F of COz/m^ Using standard ethane as a conservative flare gas proxy Tier 2a UNFCCC countiy specific E.F Tier 2b Installation specific E.F derived from esfimafing molecular weight of the flare gas stream using process modeling Tiers Activity specific E.F applying MRG Section 13, Annex 1 Minimum tier for each installation category (for major source streams) A = Tier 1 B = Tier 2a/b C = Tier 3 For liquid fuels DBERR has accepted Tier 2a to be appropriate for the offshore sector and specified the use of O&GUK emission factor of 3.2 tonnes C02/per tonne diesel and the net caloriflc value as detailed in the DEFRA website ( spreadsheet. For gaseous fuels the highest Tier 3 requirements have been set for the offshore sector (unless it is technically unfeasible or would lead to unreasonably high costs). With a minimum of quarteriy sampling frequencies set for homogeneous gases and monthly sampling set for heterogeneous gases. For flare emissions DBERR has accepted Tier 2b to be achievable for the offshore sector, whereby using process modeling to estimate the gas composition of the flare gas sfream.

8 .'js'r Oil & Gas Emissions Seminar Oxidation Tiers The tiers specified for the oxidation factor covering fuel emissions and flaring emissions are given in Table 4. Table 4 - Oxidation Tiers Combustion Emissions Fuel Flaring Tierl Factor 1.0 Factor 1.0 Tier 2 UNFCCC country specific factor UNFCCC country sf^ecific factor Tiers Fuel specific factor N/A Minimum tier for each installation category (for major source streams) A, B & C = Tier 1 A, B & C = Tier 1 For liquid and gaseous fuels DBERR has assigned Tier 1 as the only applicable tier. For flare emissions DBERR has set a Tier 2 requirement for the offshore sector, as specified in the DBERR guidance document [4]. Measurement Uncertainty The Guidelines require written proof of the measurement uncertainty levels reported for activity data and place an emphasis on comprehensive measurement uncertainty analysis. The operator is required to have an understanding of the main sources of uncertainty which should reflect not only the measurement uncertainty associated with instrument calibrations but also measurement uncertainty associated with how the instrument is used in practice. Measurement uncertainty calculafions are required for all source streams contributing to the total annual emissions. The Guidelines require operators to take into account the cumulative effects from all components in the measurement system using the en-or propagation law given in specified standards. These include ISOrTAG 4 [5]. ISO-5168:2005 [6] and Annexl of the Revised 1996 IPCC Guidelines [7]. Although measurement uncertainty Is not specified for the emission factor, where Section 13, Annex 1. of the Guideline applies, the data must be reported to within a 1/3 of the uncertainty level achieved for activity data for the same source stream; othenwise more frequent sampling is necessary. Calibration Operators are required to ensure that the relevant measurement instruments are calibrated, adjusted and checked at regular intervals prior to use. This involves the checking of instruments against measurement standards that are traceable to intemational standards, where available. Where instruments cannot be calibrated (e.g. fiare gas meters), the operator must idenfify this in the monitoring plan and propose altemative methods of achieving control and verification. Fall-Back Approach In cases where it is not practicable on both technical and cost grounds to apply Tier 1 to all major and minor source streams, the regulator may allow the operator to adopt the fallback approach.

9 This exempts the operator from applying the tier system described above and instead allows a customised approach to be used. However, in doing so the operator must demonstrate that the customised approach can, over the fijil reporting period, meet the fallback uncertainty limits outlined below and demonstrate such taking into account the ISO/TAG 4 standard. Table 5- Fall Back Measurement Uncertainty Limits Installation Category A B C Uncertainty threshold ± 7.5% + 5.0% ± 2.5% Where the fall back approach is used the member state is required to notify the European Commission. Installations with low emissions In circumstances where the average reported verified emissions from the installation for the previous reporting period is less than 25 ktonnes, the Guidelines allows the operator to determine activity data from fuel purchasing records and stock esfimates without further consideration of uncertainty. It also gives exempfions to the rules on calibration and Is more lenient on tier requirements. However, it is highly unlikely that this circumstance will apply to offshore UK installations. 3 IPPC DIRECTIVE 3.1 Background The IPPC Directive is implemented offshore by DBERR under the Offshore Combustion Installations (Prevention and Control of Pollution) Regulations [8], otherwise known as the Offshore PPC Regulafions. They apply a comprehensive approach to the environmental regulation of combustion processes used to generate power on offehore facilities (with the exclusion of operational or emergency flaring of gas and incinerators). The Regulations are controlled by the issue of permits which are based on the use of Best Available Technique (BAT) that balance the costs to the operator against the benefits to the environment. The overall aim of the Regulations is to prevent emissions, and where this is not practicable, reduce them to within acceptable levels. PPC permits are required for offshore oil and gas facilities where the aggregated thermal input of the combustion plant on the facility exceeds 50 MegaWatt thermal (MW(th)). The themial capacity of combustion equipment is a function of the equipment manufacturer's Maximum Continuous Rating (MCR), the efficiency of the equipment and the calorific value of the fuel. Although the Offshore Regulations were implemented in 2001, only new installations after this period were required to obtain a PPC permit. However, under the Regulations all existing offshore installations exceeding the threshold were required to obtain a permit by 1 November This resulted in the issuing of 81 offshore permits on the run up to the 1 November 2007 deadline. The permits, although not setting maximum limits on emission releases, require the effecfive monitoring and reporting of key pollutants from specific combustion plant.

10 V. Oil & Gas Emissions Seminar 3.2 Pollutants The main offshore pollutants subject to monitoring and reporting under ttie Regulations are: oxides of nitrogen, and other compounds containing nitrogen oxides of sulphur, and other compounds containing sulphur carbon monoxide methane non-methane Volatile Organic Compounds 3.3 Combustion Riant Combusfion plant is that which uses either gaseous or liquid fuels to generate energy for the operation of the facility. This covers bofii major and minor equipment and generally includes: turt>ines intemal combustion engines (ICE) i.e. diesel engines fired heaters used to heat any medium inert gas generators Due to the potential environmental impact a greater emphasis is placed on major equipment such as gas turbines, and in some cases diesel engines, when relied upon as the main power source for the facility. The permit application requirements are less stiingent for minor combustion equipment, or equipment that is rarely used. 3.4 Monitoring and Requirements Emissions monitoring is required for all main combustion equipment covering all machine loads representative of normal operating conditions (unless the equipment has either a tiiermal capacity less than 2MW(th), is run for less than 1000 hours per annum, or, is mn on diesel and the total emissions from all diesel use on the installation is less than 4% of the tota! emissions). The monitoring of emissions involves periodic stack sampling of the flue gases using accredited bodies. The frequency of sampling is specified on a case-by-case basis under the conditions of the permit Some operators have indicated this to be every 3 years. The reliability of CEMS for emissions monitoring, although used extensively onshore for PPC stack sampling, has not as yet been demonstrated as satisfactory for offshore applicafions. The use of Predictive Environmental Monitoring Systems (PEMS), which correlate emissions using combustion plant emission profiles versus load, is not seen as a subsfitute for stack emissions monitoring. At best, PEMS may reduce the sampling frequency and monitoring requirements. It Is recognised that the accuracy of PEMS can be increased if used in conjunction with fuel gas metering of the specific combusfion equipment. Due to the difficulties involved in both controlling emission levels and implementing emissions monitoring equipment offshore, especially for older plant and installations, DBERR has pennitted

11 the approach of controlling mass emissions of the pollutants from the entire facility, on a calendar- year basis, as opposed to monitoring mass emissions per unit volume of exhaust gas from each item of combustion plant. The latter is the method used for PPC monitoring and reporting onshore. Operators are required to report their mass emissions through the European Pollutant Emission Register (EPER) every 3 years and in addition submit quarteriy and annual emissions reports via the Environmental Emissions Monitoring System (EEMS) database. 4 REFERENCES [1] Directive 2003/87/EC of the European Pariiament and of the Council of 13 October 2003 establishing a scheme for greenhouse gas emission allowance trading within the Community and amending Council Directive 96/61/EC [2] Integrated Pollution Prevention and Control Directive (96/61/EC of 24 September 1996 concerning integrated pollufion prevention and control [3] Commission Decision of 18/VII/ establishing guidelines for the monitoring and reporting of greenhouse gas emissions pursuant to Directive 2003/87/EC of the European Pariiament and of the Council [4] EU Emissions Trading Scheme Guidance to Operators on the requirements for installations to achieve the highest applicable monitoring tiers (as defined within Commission Decision of 18 July 2007 establishing guidelines for the monitoring and reporting of greenhouse gas emissions known as MRG2) - Guidance to Operators of Offshore Installations (Incorporating Frequentiy Asked Quesfions) - Final Version - September 2007 [5] Guide to the Expression of Uncertainty in Measurement, ISO/TAG 4. Published by the Intemational Standardisation Organisation (ISO) in 1993 (corrected and reprinted, 1995) in ttie name of the BIPM, lec, IFCC, ISO. lupac, lupap and OIML. [6] :2005 Measurement of fluid flow - procedures for the evaluation of uncertainties. [7] Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories - Annex 1, Managing Uncertainties [8] Offshore Combustion Installafions (Prevention and Control of Pollution) Regulations 2001 (SI 2001 No. 1091) amended under Statutory Instnjment No. 2007/938, 10