A Review of Flare and Vent Gas Emissions Monitoring - · PDF filea review of flare and vent gas emissions monitoring and ... review of flare and vent gas emissions monitoring and reporting

SUMMARY REPORT A REVIEW OF FLARE AND VENT GAS EMISSIONS

MONITORING AND REPORTING METHODS

An Overview of Methods Used by Industry

The work described in this report was carried out by TUV SUD Ltd under contract to the Department for Business, Innovation & Skills („the Department‟) as part of the National Measurement Office‟s Engineering & Flow Programme. The Department has a free licence to copy, circulate and use the contents of this report within any United Kingdom Government Department, and to issue or copy the contents of the report to a supplier or potential supplier to the United Kingdom Government for a contract for the services of the Crown. For all other use, the prior written consent of TUV SUD Ltd shall be obtained before reproducing all or any part of this report. Applications for permission to publish should be made to: Contracts Manager NEL Scottish Enterprise Technology Park East Kilbride G75 0QF E-mail: [email protected] Tel: +44 (0) 1355-593742 © TUV SUD Ltd 2013

mailto:[email protected]

NEL

Project No: FHRE03 Page 1 of 26 June 2013 Report No: 2013/286

NEL

East Kilbride GLASGOW G75 0QF

UK Tel: +44 (0)1355 220222 Fax: +44 (0)1355 272999

www.tuvnel.com

SUMMARY REPORT OF REVIEW OF FLARE AND VENT GAS EMISSIONS

MONITORING AND REPORTING METHODS

A Report for

National Measurement Office Stanton Avenue

Teddington TW11 0JZ

Prepared by: Jeff Gibson Date: 6 June 2013 Approved by: Alick MacGillivray Date: 6 June 2013 for B Millington Director

http://www.tuvnel.com/

NEL


C O N T E N T S Page EXECUTIVE SUMMARY

3

1 INTRODUCTION

5

2 BACKGROUND

5

2.1 Gas Flaring and Venting Processes 5 2.2 Flare Gas and Vent Gas Composition 6 2.3 Worldwide Flaring Statistics 7 2.4 Flare Systems 7 2.5 Reducing and Reusing the Gas Normally Flared 7 3 FLARE GAS REGULATION 9 3.1 Flare and Vent Regulation 9 4 REGULATORY MEASUREMENT REQUIREMENTS FOR FLARING

AND VENTING 11

4.1 4.2

EU Emissions Trading Scheme Flare Measurement Requirements Prominent Flare Measurement Requirements in other regions

11 13

5 FLARE GAS FLOW MEASUREMENT TECHNIQUES USED BY

INDUSTRY 13

5.1 General points to consider when measuring flare gas flow 13 5.2 Flow Measurement methods available 15 6 DETERMINATION OF FLARE GAS COMPOSITION 20 6.1 Manual Gas sampling, with Offline Analysis by Gas Chromatograph 20 6.2 Automatic Gas Sampling and Offline Analysis by Gas Chromatograph 20 6.3 Online Gas Chromatographs 21 7 DIRECT EMISSIONS MEASUREMENT TECHNIQUES 22 7.1 Optical Remote Sensing (ORS) Techniques 22 8 CONCLUSIONS 24 8.1 Meter Performance 24 8.2 Improving Meter Performance 24 8.3 Calculation Methodologies 25 9 RECOMMENDATIONS FOR FURTHER WORK

REFERENCE

26 26

NEL


EXECUTIVE SUMMARY This report provides a summary of the findings of a review undertaken by NEL to investigate the techniques used by industry to measure and report flare gas emissions; the work was funded by the National Measurement Office, an Executive Agency of the UK Department for Business, Innovation and Skills (BIS) [1]. The main objective of this work is to support industry in meeting their legal obligations for measuring and reporting flare gas emissions It is estimated that every year, some 360 million tonnes of CO2 is released to the atmosphere through flaring and venting1. This has a detrimental effect on the environment, contributing significantly to global warming and acidification of both land and sea. A considerable proportion of this CO2 comes from the production of Oil and Gas. This report describes the legislation currently in place in different parts of the world to limit emissions from this sector and suggests modifications to existing techniques to improve measurement accuracy. Currently, the most prominent legislation has been developed in the European Union, the United States, Norway and Canada. The European Union Emission Trading Scheme (the EU ETS) is a mandatory cap-and-trade scheme that sets limits on the amount of greenhouse gas emissions from energy-intensive installations. Permit holders are allocated a set amount of EU allowances and can buy or trade them according to whether they are in deficit or surplus. Failure to comply with the agreed cap is met with financial penalties - principally a fine for every tonne of CO2 for which the operator fails to surrender allowances; they must also make-up for the shortfall the following year. The legislation in the other parts of the world is also discussed in this document. To operate and further develop legislation in all of these areas, it is necessary to accurately determine the total mass of pollutant released to the atmosphere resulting from the practices of oil and gas production, refining, processing and transport. The most widely adopted approach for determining CO2 emissions is often referred to as the “Calculation Method” whereby three separate parameters must be determined pre-combustion of the gas:

The flowrate of the gas;

The composition of the gas;

The oxidation factor (a ratio of the amount of carbon converted to CO2 linked to

the flare efficiency)

As far as the flowrate of the gas is concerned, the wide range in operating conditions encountered in flaring mean that the technologies used must have a broad range of application. The three principal technologies currently being deployed within emergency flare lines on large oil and gas facilities2 are:

Ultrasonic transit time meters,

Thermal mass probes,

Optical correlation meters

These are generally single point or single path measurement devices that are sensitive to flow profile and installation effects. The study concluded that using multiple

1 Source: World Bank Global Gas Flaring Reduction partnership: www.worldbank.org/ggfr

2 These include oil and gas production facilities, refineries and chemical plants. Other metering

technology may be used in some circumstances or on smaller, more controlled flare and vent lines.

http://www.worldbank.org/ggfr

NEL


measurement probes or meter technologies - each tuned to a different range (e.g. an ultrasonic meter for the low range and an optical meter for the high range flow) - could improve accuracy over the full operating range. It also concludes that operators should focus their efforts on optimising their meters to achieve maximum accuracy for the flow regions in which the majority of gas volume is flared over the reporting period. In addition to the flowrate, flare gas composition is required to determine the quantity of specific pollutants flared or vented to the atmosphere. It is normally determined from captured fuel gas samples using an analyser such as a gas chromatograph. Various types are available and are reviewed. However, sampling from the flare line itself is generally precluded owing to issues with health and safety, a lack of pressure in the line (or a risk of sudden, unpredictable rises in line pressure during incidents such as compressor trips, power failures or emergencies), and other technical issues. In addition to reviewing existing methods for determining flare emissions, the study also looks at novel and developing technologies. One such technique is Optical Remote Sensing (ORS) which potentially provides a means of directly measuring and tracking the emission of pollutants from a flare plume. The ORS method is very useful for both detecting and quantifying fugitive emissions. The key recommendations for further work are:

An investigation into installation effects should be carried out for the most widely used flare gas meter technologies to derive the true measurement uncertainty.

In many cases, a significant proportion of the total gas flared (and, hence, the CO2 released) will emerge from the low-flow end. Therefore, there is a clear need for this region to be fully investigated, focussing on issues concerning: signal resolution, laminar/turbulent transition and temperature stratification.

Meter errors arising from high and low flaring should be investigated and the associated measurement uncertainty accounted for in all calculation and reporting sheets.

There needs to be a methodical and thorough test program investigating laminar-turbulent transition, stratification and installation effects at low velocities in large pipes simulating typically-sized flare lines.

Gas tracer techniques offer a method of assessing flare gas flow meters in situ with the actual upstream pipe configuration and prevailing flow conditions. However, a comprehensive study assessing the technique as employed in flare gas lines is needed to fully assess the capabilities and a realistic uncertainty level in the technique.

Issues relating to the uncertainty in the flare gas composition during process blowdowns should be investigated where it impacts density and emission factor

Optical Remote Sensing technologies – and other direct methods of determining gas emissions - should be further investigated where it may be applied to flare, vent and other fugitive gas emissions in the future.

The most comprehensive approach to investigation of the above issues should ideally take the form of a large, collaborative project involving industry leaders, equipment supplier, regulators and technical consultants where possible.

NEL


Offshore Flaring

1 INTRODUCTION This report provides a summary of the findings of a thorough review undertaken by NEL to investigate the techniques used by industry to measure and report flare gas emissions [1]. The main objective of this work is to support industry in meeting their legal obligations for measuring and reporting flare gas emissions; in particular, it will assist in moving towards CO2 trading within Phase III of the EU Emissions Trading Scheme (ETS), due to commence on 1 January 2013. The findings of this report will assist operators and stakeholders of oil and gas facilities to identify key areas for improvement in the method of determining flare gas quantities and, where appropriate, the amount of CO2 released through combustion of the gas.

2 BACKGROUND It is estimated that over 150 billion cubic meters (bcm) of natural gas is flared or vented globally every year. To put this in to context, this is some 30% of the European Union‟s annual gas consumption, or an amount worth approximately $30.6 billion - enough gas to supply the entire US economy for three months.

Over the next two to three decades, global energy demand is predicted to double, while oil and gas reserves are largely depleting. It is a widely held opinion that renewable energy sources, which currently only supply a small proportion of the world‟s energy, will not be in a position to make up the shortfall in the foreseeable future. In addition to wasting valuable energy resources, flaring also contributes to climate

change and global warming. The World Bank estimates that around 360 million tonnes of CO2 is emitted from gas flares each year. The focus of this report is on CO2 emissions, since the reporting of emissions of the other pollutants from flares is not as stringent in EU legislation (except for highly toxic gases such as H2S) and are, as yet, excluded from the EU ETS. However, reference is made to these gases where it is deemed applicable.

2.1 Gas Flaring and Venting Processes

Flaring is a necessary process by which excess gases can be evacuated quickly and safely in emergency situations; it is also used to facilitate depressurization of plant for maintenance and inspection during shutdown. It takes place across a number of industries and activities - including oil and gas production, refineries and petrochemical plants. Flares are also to be found at coal bed methane facilities, steel production plants and landfill sites.

The flare, which often takes the form of a flame burning at the tip of an elevated stack, primarily acts as a safety relief valve. It also allows the system pressure to be regulated across the plant and prevents machinery and components from being over-pressurised. In many cases, a portion of the gas flared is taken from the fuel gas system and used to maintain a positive pressure at the tip, thus keeping air out of the system avoiding potential blow-back of the gas. This process is often referred to as purging. Gas production facilities tend to flare less than their oil counterparts due to their inherent connection to existing gas pipeline or gas processing plants. Gas venting releases gas directly into the atmosphere and tends to be more prevalent on gas production than for oil wells. Since

NEL


its environmental impact can be greater than if the equivalent amount of gas was flared, venting should only be used as a last resort.

2.2 Flare Gas and Vent Gas Composition

2.2.1 Gas Flaring

The emissions from flares and vents depend on a number of factors, one of the most important of which is the composition of the waste gas being burned or vented. On offshore platforms the bulk of gas routed through the flare is often made up of methane and lower fractions of various other higher alkane hydrocarbons, hydrogen sulphide (H2S) and inert gases - typically in smaller fractions. Flare gas composition tends to be more complex onshore than offshore owing to the processes involved.

Flaring is largely considered less harmful to the environment than venting. This is, in part, due to the fact that the Global Warming Potential of natural gas is higher than that of CO2. Highly acidic compounds, such as carbonic acid (H2CO3), sulphuric acid (H2SO4) and nitric acid (HNO3) may also be formed if the flare gas stream contains high enough fractions of water. These will cause pipework and fittings to erode unless acid-resistant alloys, or coatings, are used. Flaring does not only produce CO2. Inefficient flaring also generates unburned hydrocarbons and pollutants, such as nitrous oxides produced at flame temperatures in excess of about 1200°C. It also produces sulphur dioxide (SO2), formed by combustion of H2S, or other sulphur compounds inherent in the fuel; carbon monoxide (CO), and particulates (smoke). The fraction of these components will be higher when the combustion efficiency is not 100% - where flame temperatures can be too high and oxygen levels too low to completely oxidise all of the VOCs (Volatile Organic Compounds) present in the gas stream.

2.2.2 Gas venting

According to DECC (Department of Energy and Climate Change), Venting in the UK reportedly makes up only 0.05% of total emissions from offshore sites and onshore terminals collectively - expressed as a mass of equivalent CO (tCO2e). In contrast, offshore flaring makes up 21% of total CO2 emissions. However, in the USA offshore operators are venting, on average, about 70% more than they are flaring. There is evidence to suggest that fugitive emissions (which are invisible to the naked eye and difficult to both detect and measure) could be even more of an issue worldwide. This situation is exacerbated by the increased effect the direct release of VOCs and other gases has on the environment and the increased global warming this causes compared with CO2.

NEL


Table 1: Ten Largest Flaring Nations

Country World flaring (% by volume)

1 Russia 26.7

2 Nigeria 10.4

3 Iran 8.1

4 Iraq 6.7

5 USA 5.1

6 Algeria 3.6

7 Kazakhstan 3.4

8 Angola 2.9

9 Saudi Arabia 2.6

10 Venezuela 2.5

TOTAL 70.0

2.3 Worldwide Flaring Statistics

Table 1 lists the ten largest flaring countries as presented by the World Bank Global Gas Flaring Reduction Partnership (GGFR) for the year 2011. These countries constitute around 70% by-volume of global flaring. It should be noted that Table 1 is dominated by developing countries. The USA is only fifth on the list, making-up just over 5% of worldwide flaring in 2011. There has been an increase in flaring from 2010 to 2011 of about 2 bcm overall, largely resulting increased hydrocarbon production in Russia, and the increase in shale oil and gas production in the USA.

2.4 Flare Systems

A flare system generally comprises: pressure relief valves feeding into the flare header, piping runs to direct the gas to the flare line, knock-out drums (cylindrical vessels which are used to separate-out liquids and any solids), and a pilot system to ignite the gas on exit from the stack. The design of flare systems varies significantly from one plant or process to another. In addition to elevated flare stacks (prevalent on most offshore oil platforms and also used onshore), ground-based flares are often used at onshore oil and gas facilities to dispose of excess gas under more routine operations. Elevated flares on oil and gas

facilities are typically 30 to 100 metres high and are generally used for higher volumes of gas. Ground flares can be open (so-called “pit flares”) or contained within refractory-lined steel enclosures. They typically comprise a number of burners set out in a matrix arrangement which promote air inspiration, increasing combustion efficiency without the need for air/steam injection. Many flare systems in developing countries such as Nigeria, comprise little more than open pipes burning-off the gas over a “cooling pond”, with no fencing or barriers to prohibit the public from exposure to naked flame, or the harmful gases and smoke produced.

2.5 Reducing and Reusing the Gas Normally Flared

A number of methods can be used to reduce gas flaring on individual installations, although some require much greater levels of investment than others. The most basic approach is to simply reduce leakage from plant and equipment by instigating preventative maintenance measures. Using efficient plant design and equipment can also significantly reduce the throughput of gas flared. There are a number of relatively low-cost techniques available to identify leakage from pipework, valves and fittings on plants. Traditionally gas-leak detectors (“sniffers”) have been used in the oil and gas industry to detect fugitive leaks from relief valves etc. Systems are available that can both identify and measure the leakage rate of gas passing from the plant. Some use ultrasonic or acoustic sensors to both detect and quantify leaks.

NEL


One of the key methods enabling the capture of substantial amounts of flare gas is Flare Gas Recovery (FGR). FGR systems effectively allow the flare to be shut-off under normal, low-pressure operation, with the gas thereafter compressed and re-routed for other uses. These systems have been installed in a number of facilities and can ultimately lead to “near-zero” flaring from oil and gas facilities, refineries and processing plants. One of the main problems of implementing FGR systems can be the required space. Space and weight is often at a premium on offshore facilities. It will also be expensive to install and the benefits of installing the technology need to be assessed over the remaining life of the facility. The scope for reducing flaring comes from reusing the gas normally sent to the flare. This can be achieved by one or more of the following methods:

Table 2: Methods for Flare Reduction

Export by pipeline Either: a) re-compressing and treating the gas to sales pressure and quality or b) exporting for use to generate power on a neighbouring facility as a fuel.

Power generation This involves reusing the gas to power equipment on the installation (such as gas turbines-driving-compressors, boilers and engines etc.), or by providing energy to local communities.

Re-injection This involves re-injecting the gas back into the formation to promote Enhanced Oil Recovery (EOR) or into the annulus of the well bore to facilitate Gas Lift.

LNG and Gas to Liquids (GTLs)

In the absence of a gas pipeline, consideration can be given to producing Liquefied Natural Gas (LNG) or Gas to Liquids (GTLS), such as Methanol or Dimethyl Ether, and exporting via ship or road.

NEL


3 FLARE GAS REGULATION Although there are clear arguments for reducing gas flaring based on energy waste and environmental impact alone, incentives have to be in place to ensure industry meets their emissions reduction targets. Flare gas reduction and utilisation is highest in developed countries which have an established gas infrastructure. For example, the utilisation of gas produced in Russia and Nigeria as a percentage of the volume of actual gas produced is only about 25% and 60% respectively (i.e. about 75% and 40% of the associated gas is flared), compared with 95 - 100% in many other regions. These are consequently the two largest flaring nations in the world. Naturally, the effective regulation of gas flaring relies heavily on accurate measurement. This is essential to ensure fair and transparent trading, and to help reduce financial exposure to stakeholders. 3.1 Flare and Vent Regulation

To-date the most prominent regulatory regimes exist in the EU, Norway, Canada and the United States, although just about all countries now at least accept that flaring has to be reduced.

3.1.1 European Union (EU Emission Trading Scheme (ETS)

The EU ETS is a mandatory scheme that sets limits on the amount of greenhouse gas emissions emitted from energy-intensive installations. Ultimately this allows an emission ceiling to be established at all levels including, company, sector, member state and European level.

Introduced in 2005, the EU ETS was originally aimed at targeting all six greenhouse gases identified under the Kyoto protocol, but has thus far concentrated mainly on CO2. It covers CO2 emissions from installations such as power stations, combustion plants, oil and gas facilities and iron and steel works.

The EU ETS is in three Phases as illustrated in Table 3;

Table 3: Description of Stages of EU Emissions Trading Scheme

Phase of Scheme Description

Phase I (2005-2007)

Essentially a trial period designed to get operators and regulators used to trading before commencement of Phase II

Phase II (2008-2012)

Timed to coincide with the Kyoto period, Phase II included offshore gas flaring as mandatory, and introduced revised Monitoring and Reporting Guidelines (MRG 2007) which focused on verification and integrity of measured data.

Phase III (2013-2020 and onwards)

Phase III of the EU ETS commenced in January 2013 and sees many having to buy allowances from the registry (via auctioning) for the first time. A new Monitoring and Reporting Regulation (MRR), and more stringent guidelines for verifiers have also been introduced.

The basis of the EU ETS is to control the level of emissions through greenhouse gas permits (allowances). The permit holders (i.e. operators and stakeholders) are

NEL


allocated a set amount of EU allowances (EUAs) with 1 allowance = 1 tonne of CO2. At the end of the reporting period the permit holder can either buy EUAs from the registry to make up any shortfall, or sell surplus EUAs back into the scheme at the going market value. Fines are imposed on permit holders emitting more than their agreed limits set by the regulator, or for misreported data. It is hoped that Phase III will see the EU achieve two-thirds of its required unilateral emissions reduction target of 20% by 2020, based on 1990 levels (equating to 500 million tonnes of tCO2 per year). 3.1.2 Other International Legislation

Table 4: Description of International Flare Gas Legislation

Country Description of Legislation

USA

The US Environmental Protection Agency (EPA) have the authority under the Clean Air Act (as Amended, 1990) to request emissions data from operators under the requirements of federal Rule 40 CFR 98 Subpart W, which includes flare emissions. There are two government departments regulating safety and the environment: The Bureau of Safety and Environmental Enforcement (BSEE) is responsible for regulating offshore federal leases, and the Bureau of Land Management (BLM) regulates onshore federal lands. The majority of oil and gas lies offshore. BLM is responsible for more than 63,000 federal onshore oil and gas wells (about 11% of all gas production in the US and 5% of oil). EPA Final Rule 40 CFR, Part 60 subpart Ja details New Source Performance Standards (NSPS) targeting refineries with new or reconstructed flare systems, or those existing, constructed or modified after June 24 2008, that have been altered to increase flow, or have had new connections added. Some 400 refineries across the US are affected by the Rule.

Canada

Canada is the third largest gas producing country in the world after Saudi Arabia and Venezuela; a large proportion of this gas is to be found in the landlocked province of Alberta, which has a large number of sour gas wells with particularly high fractions of sulphur present. Canada has had legislation in place for a number of years governing flaring – largely developed from the need to reduce and control emissions from sour gas. The legal requirements in Alberta are laid down in the Energy Resources Conservation Board (ERCB) Directive D060. The legislation provides a comprehensive approach for reducing and measuring flare gas emissions. D060 requires operators of installations exceeding 100 standard m3/month of gas flared, incinerated or vented, to report these quantities to the regulator.

Norway

The Norwegian Government will not approve oil and gas development plans without there being provisions in place for reducing gas flaring. Even though Norway has doubled its oil production over the last two decades, it has managed to do this whilst significantly reducing gas flaring through a number of successful regulatory measures. Norway joined the EU ETS in 2008, However, despite this a CO2 taxation scheme, introduced in 1991, still continues, together with a NOx tax more recently introduced in 2007. These are based on the amount of gas burned in flares, engines and turbines. The CO2 tax has also contributed to the successful reduction of flaring. In Norway, a large amount of gas is re-injected for Enhanced Oil Recovery (EOR) and other purposes.

NEL


4 REGULATORY MEASUREMENT REQUIREMENTS FOR FLARING AND VENTING The common feature across most regulatory regimes is the requirement for operators to report their emissions using transparent and robust methods that are, ultimately, verifiable. The specific requirements set out by different countries are described below. 4.1 EU Emissions Trading Scheme Flare Measurement Requirements Operators must currently comply with the requirements of the EU ETS Monitoring and Reporting Regulations (MRR). The CO2 emission from flares is determined by the calculation method, whereby the volume of gas flared is measured and the amount of CO2 produced by combustion (and any inherent CO2 in the gas) is calculated through the use of an emission factor (the tCO2e emitted per unit quantity of gas flared) and oxidation factor (the amount of carbon oxidised to form CO2 during combustion). The MRR is underpinned by strict measurement uncertainty targets and a newly introduced set of guidelines for verifiers to ensure a more consistent approach is applied across the member states. Although the minimum uncertainty limits for flare were actually increased from Phase I to Phase II (and remain unchanged for the quantity (activity data) in Phase III, the requirements for verification have become progressively more stringent. The reporting of all flaring from offshore facilities became mandatory during Phase II. Phase III sees the introduction of flaring from chemical plants which was previously excluded. However, flare is, for now, given free allocation. The guidelines are not prescriptive in terms of specifying any one type of technology over another, nor do they require dedicated flow meters to be installed in the flare line. Operators have the option of using a combination of approaches, which often entails both direct metering and indirect estimation techniques, and may, if properly implemented, provide a robust reporting system. The uncertainty requirements are detailed below in Table 4 for each parameter, where applicable.

Table 5: Uncertainty values for Measured Parameters

Activity Data (Volume or Mass)

3 Tier System Larger installations (> 500 ktCO2/year) Medium-sized installations (50–500 ktCO2/year) Small sized installations (< 50 ktCO2/year)

± 7.5%

± 12.5% ± 17.5%

Emission Factor (EF) In EU ETS Phase II, the uncertainty in the flare emissions factor was required to be one-third of the uncertainty in activity data, which, strictly speaking, is ± 7.5% / 3 = ± 2.5% if the top tier is to be met. This requirement has been removed from the MRR for flare where it is stated that process modelling techniques may be used to calculate EF

Oxidation Factor There is no requirement to determine the oxidation factor to any given accuracy in the MRR and it is generally considered to be equal to 1.0 for gas flares (a value of 0.98 is used in the UK since baseline figures were calculated assuming 98% conversion of carbon to CO2 by combustion

Some studies have shown that the efficiency of flares can be considerably less than 100%, particularly in the presence of high winds, liquids and over-steaming.

NEL


4.1.1 Current UK Position within the EU ETS In the UK most upstream facilities are currently reporting flare to Tier 2 requirements (12.5%) under Phase II, with a few meeting top-tier requirements and all are using the calculation approach. However, some still rely on engineering calculation or estimation techniques to determine gas to flare. To address this issue, the UK regulator (DECC) requires yearly improvement plans to be submitted detailing how the operator plans to achieve their monitoring and reporting requirements. 4.1.2 Phase III Implications for Gas Flaring The Phase III Monitoring and Reporting Regulation replaced the MRG from the start of 2013 and aims to provide better harmonisation in the methods applied across Europe. Some of the pertinent changes to the monitoring and reporting plan in Phase III that will affect gas flaring to some degree are listed.

New Requirement for Consistent Determination of “Unreasonable Costs”

In the Phase III MRG, unreasonable cost is determined by calculating the cost involved with implementing the changes required to move to the higher tier and comparing this against the financial benefits in achieving that tier.

Promotion of consistent application of the required monitoring tiers

Measurement-based methodologies have been significantly updated

Direct measurement of CO2 emissions from flares can only be practically carried out in the few isolated situations where the flame is enclosed within a flue allowing sampling of the exhaust gases to be carried out, along with the flow rate. However, bespoke field studies have been undertaken in the US (notably in Texas), and some other countries, in order to analyse emission plumes from various emissions sources as a means of determining emission factors for various pollutants – some of which are at the ppm level. These surveys have generally been undertaken using Optical Remote Sensing (ORS) techniques.

New provisions to allow more pragmatic demonstration of equivalence where non-accredited laboratories are employed

A combination of approaches can now be used to determine emissions on the condition that no data gaps or double accounting occur as a result.

Reduced requirements for minor source streams contributing less than 5,000 tonnes CO2 per year, or up to 10% of the total CO2 emissions over the year

Introduction of Regulation on the Verification and Accreditation of EU ETS emission reports

This regulation has been introduced to ensure that verifiers possess the technical competence to perform the entrusted task in an independent and impartial manner and in conformity with the requirements and principles set out by the EU ETS.

NEL


4.2 Prominent Flare Measurement Requirements in other regions

The monitoring and reporting requirements in three key regions are listed in the Table below.

Table 6: Prominent Flare and Vent Monitoring and Reporting Regimes

USA

Federal Rule 30 CFR 250, Subpart K (introduced in 2010), requires flare gas quantities to be accurately measured by facilities located offshore in the Gulf of Mexico and US Offshore Continental Shelf (OCS) processing more than 2,000 barrels of oil per day. The measurement uncertainty is set at ± 5% on flow rate. The regulations require that flow meters are “calibrated” every 12 months. Operators were required to install flare meters on all qualifying installations within 180 days after the release of the regulations. Onshore, recently amended Federal Rule 40 CFR Part 60, subpart Ja promulgates New Source Performance Standards (NSPS) targeting emissions from flare and process heaters with a view to monitoring, reporting and reducing sulphur, NOx and VOC emissions from refineries. Amongst the requirements are that flow and sulphur monitors are now mandatory for all continuous flaring excluding intermittent, emergency-only flaring with limited release. Flare Gas Recovery systems are seen as a key technology for reducing emission from larger flares and providing some level of offset to the cost of installation through increased sales revenue of the captured gas and, to a lesser degree, performance improvements through the improved monitoring and reporting regime.

Canada

In Canada the most comprehensive monitoring and reporting requirements are set by the Energy Resources Conservation Board (ERCB) in Alberta. Directive 060 contains the requirements for flaring, incinerating, and venting activities conducted in Alberta by all upstream petroleum industry wells and facilities. Directive D017 details the monitoring and reporting requirements and specifies that, for facilities flaring more than 500 m3/day (and all flaring from sour gas wells, regardless of volume), the operator must meter the volume to ± 5% uncertainty on a single point, and a maximum uncertainty of ± 20% over a monthly period.

Norway

In Norway, offshore operators are expected to have ultrasonic transit-time flowmeters installed as the primary measurement device in all flare lines as per NORSOK I-SR-103. In addition to setting a measurement uncertainty target of ± 5% on measured volume, the Norwegian regulators also require the sensors to be checked every 6-months.

5 FLARE GAS FLOW MEASUREMENT TECHNIQUES USED BY INDUSTRY

Despite the fact that flare gas measurement has been carried out by industry for many years, it is still very much considered a relatively new science owing to the complexities and challenges involved. The measurement of emissions from flares is different to other gas flow measurement and emissions measurement applications. The unpredictable nature of flaring, and often hostile environment, amongst other things, makes measurement extremely difficult and complex.

NEL


5.1 General points to consider when measuring flare gas flow 5.1.1 Meter Rangeability It is essential that any measurement equipment installed in the flare stack does not obstruct gas flow in any way and incur significant pressure drop. The large variation in flare operating conditions can lead to a wide range of gas flow velocities, particularly if only one flare is being used on the plant. It is therefore essential that the flow meter(s) installed in the flare have the rangeability to cope with these sorts of excessive measurement ranges and, moreover, will not be permanently damaged by the forces generated on transducers during such events. 5.1.2 Physical Properties Changes in viscosity and density have a significant effect on the flow profile through variations in Reynolds Number. Also, at low velocities, stratification, transient and reverse flows are common. All of these conditions give rise to complex flow measurement. The changing operating conditions can also induce large variations in gas temperature, and the gas composition can change dramatically - especially during blowdown conditions. 5.1.3 Pipe Geometry The diameter of flare lines can range from as little as 4-inches (0.1 m), on some small onshore wells, up to 72-inches (1.8 m), or even larger, in refinery and offshore flares, although flare lines typically tend to range between perhaps 12- and 40-inches. This will also limit the choice of many flow metering technologies. When flare gas meters are required to be retrofitted to existing flare stacks - which is often the case offshore - space (and weight constraints) can be a serious issue, particularly offshore. Inadequate straight lengths of pipe upstream (and downstream) will result in asymmetrical flow profiles and swirl that will affect the meters performance and introduce a measurement error. 5.1.4 Sampling Obtaining a composition measurement, or extracting a representative sample direct from the flare stack for analysis, especially during emergency blow-down events, can be an impossible task. In any case the gas will likely be too wet, dirty or at too low a pressure to allow onsite analysis using Gas Chromatographs (GCs). Environmental factors also have to be considered when selecting measurement equipment. This includes the explosive environment and the presence of corrosive components in the gas stream (e.g. H2S and CO2) plus potentially highly corrosive acids and other dangerous substances. 5.1.5 Flow Profile Issues One of the key issues in flare gas measurement is the failure to quantify upstream installation effects on flow profile, and the subsequent impact this has on the measurement uncertainty. Bends, valve, tees and reducers disturb the flow such that the velocity profile deviates from the ideal. For example, the flow profile can become skewed, with non-axial flow components (swirl) present. Meter manufacturers generally advise having at least 20 diameters of straight length pipeline upstream of the meter (and, typically, 5 to 10 downstream of it – although this is less important).

NEL


A flowmeter may under-read or over-read depending on the installation, flow conditions and orientation and location of the measurement sensors and the permutations are numerous. At high flow rates this error will tend to be steady, but it may fluctuate at lower flow rates due to instability in the flow profile. Computational Fluid Dynamics (CFD) simulation offers a very flexible and cost-effective alternative to determining meter error for all types of flow meter. CFD involves modelling the velocity and turbulence through a 3-Dimensional grid representing the flare header and flowmeter installed within it. The uncertainty in the CFD method can only be validated by comparing its predictions against relevant test data from technical papers and journals. Figure 1 below shows the predicted streamlines through a pipework header and the resulting distortion to the velocity profile – the velocity contours are clearly asymmetric at the flow meter position compared to the ideal, fully developed case. Figure 1: CFD Modelling of the Flow (Streamlines) through a Pipe Header and the

resulting Velocity Contours at the meter (Red/Blue = high/low velocity)

5.2 Flow Measurement methods available Although there are a number of different flow metering technologies that may potentially be used for flare gas measurement, the most widely used flow meter is the time-of-flight Ultrasonic Meter (USM). Its main advantage is its very wide turndown ratio (quoted as up to 2,500:1 and even higher), reportedly low measurement uncertainty, absence of moving parts, non-invasive design and, thus, suitability in large diameter pipelines. Other dedicated flare gas metering technologies that can be considered are thermal mass probes and optical meters. Other insertion probes, such as averaging pitots, turbines and vortex meters, have low rangeability compared with the aforementioned meters. They are not as commonly used as a single, dedicated flare meter, however, they may be effectively used as a secondary meter to target a specific range (e.g. an averaging pitot scaled for high velocity use). 5.2.1 Flare Gas Ultrasonic Meters (USMs) Most flare gas USMs employ single beam-paths, mostly due to cost. Unfortunately, this means that they are particularly sensitive to the flow profile compared with multiple path meters (usually restricted to higher-accuracy custody transfer and fiscal applications).

Flowmeter

position Fully Developed

Profile (Reference)

Flow Profile at

meter position

NEL


Some two-path flare gas USMs are in use which, in theory (and assuming uncertainties to be uncorrelated), reduce the uncertainty in the average velocity by about 30% compared with a single path, but if the flow is approaching fully developed without swirl or significant asymmetry. The main issues associated with this type of meter are detailed in the table below.

Table 7: Measurement Issues for Ultrasonic Flare Meters (USMs)

High flow rates The main issues at high flow are: signal-to-noise ratio (SNR), beam drift and response to sudden changes in flow – all of which may also cause a misreading or loss of signal. Provided enough samples are taken, a good averaged velocity will be obtained using the meter‟s digital signal processing algorithms.

Ultrasonic Noise This can cause problems with the signal resolution and may result in a failure of reading. Care should be taken during installation and set-up to ensure all potential sources of noise “leakage” through the pipework, bosses and couplings are eliminated.

Beam Drift at

High Velocity (Mach Number)

A key issue exclusive to ultrasonic meters is beam drift at high flowrates. The simplistic view that the ultrasonic signal travels along a direct path between the faces of the two opposing ultrasonic transducers is only true at low velocities (and, more correctly, low Mach numbers). The path direction is affected by both the Mach number and the shape of the velocity profile. At the very high velocities experienced in flare gas lines, the ultrasonic signal can be so badly affected by this it can be lost entirely – effectively “blown away” by the flowing gas.

Low Flow Issues

Besides the large uncertainty that can be apparent in low flow associated with the instability and variability in the flow profile at low Reynolds number the resolution of the meter will also be a key issue at low flow.

Effect of Gas Composition

on Volume Flowrate

Measurement (USMs)

In theory, the reading of velocity should be independent of the gas composition. However, one exception is where the gas contains CO2 which can absorb ultrasound at frequencies in a similar range to where flare meters normally operate due to a phenomena called “signal relaxation” that occurs CO2 with some other gases at specific frequencies. This issue can be relatively easily resolved using special transducers with a modified frequency.

5.2.2 Thermal Mass Probes The basic principle of operation of a Thermal Mass Flowmeter (TMF) is that the convection from a heated Resistance Temperature Detector (RTD) is proportional to the mass flow rate of the flowing gas. In theory, no measurements of pressure or temperature are needed to get an accurate measurement of mass flow rate. Thermal mass probes typically comprise two (or more) cylindrical sensor probes mounted on the end of an insertion bar. One of the probes in a sensor pair is electrically heated and acts as the active sensor, whilst the other measures the local static temperature. Sensors specifically targeted at flare gas application tend to use the constant power method.

NEL


The output from a thermal mass probe is non-linear and varies as a function of both thermal properties (i.e. gas specific heat capacity, thermal conductivity) and the probe Reynolds number. They are therefore inferential mass flow meters that, whilst their output is proportional to mass flow, are affected to some degree by process conditions and gas composition. One particular model of TMF specifically targeted at flare gas applications includes a method of compensating for changes in gas composition. These meters comprise a second set of measurement sensors located in separate chamber; the sensors respond to changes in gas composition and allowing online correction to be applied to the output signal. 5.2.3 Optical Correlation Flowmeters

Optical meters are velocity (volumetric) meters and operate on the principle that localised disturbances - such as turbulence, or tiny particles inherent in the gas stream - perturb one or more incident light beams which then provide a signature pattern that can be tracked between two optical sensors placed a known distance apart. Correction factors are then applied to determine average velocity and volumetric flow rate if

the pipe diameter is known. Like ultrasonic technology, optical meters also have the ability to measure bi-directional flows and, therefore, detect potential problems with backdraft and/or instabilities arising from insufficient purge rates. A major advantage of optical meters is that they do not interact with the flow and are, thus, insensitive to changes in gas composition, pressure or temperature. Unlike ultrasonic meters, they are, therefore, less prone to loss of signal at very high flowrates. Several commercial designs of optical meter are currently available. One such type uses high-intensity laser light beams focussed onto two small photo-detectors located side-by-side in the gas stream. Microscopic particles inherent in the gas stream pass through the two laser beams causing the light to be scattered onto the detectors providing a characteristic signal pattern that can be used to determine the gas velocity. A correlation technique is then used to determine the time-of-flight of the gas between these two positions, thus allowing velocity to be determined. This meter is available as a single insertion probe for large line sizes, or a flanged “wafer” design for line sizes below 6-inch (the latter allowing the meter to be installed between two existing flanges during a shutdown). In the case of the insertion probe design, the measurement window is small and, thus, provides only a point-velocity measurement. The advantage of the single insertion probe design is its ease of installation, especially compared with the precision welding required for flange connections for ultrasonic probes. Being effectively a point-measurement device, this meter is sensitive to flow profile (although this is true of all flare gas meters to some degree). Test data has been made available by the manufacturer, including data showing installation effect due to upstream headers and double-bend configurations carried out in 6- and 12-inch line. Similar velocity and accompanying uncertainty ranges are quoted for this technique as for the laser-based technology. A major advantage of optical meters is that they do not interact with the flow and are, thus, in the first instance, not sensitive to changes in gas composition, pressure or temperature. A second type of optical meter specifically marketed at flare gas incorporates a visible L.E.D. light beam that passes through the gas from one side of the pipe to the other. The light beam falls onto two detectors placed a known distance apart in the axial direction. The detection method in this case is the scintillation (i.e. “twinkling”) of the light in response to changes in gas density due to temperature changes and/or

NEL


turbulence. The scintillation produces a characteristic pattern on the first beam which is then picked up a short time after by the second. Once again, cross-correlation is used to get the time-of-flight between the two detectors and, hence, velocity.

Figure 2: Cross – correlation technique 5.2.4 Indirect Measurement Techniques Indirect measurement techniques involve estimation of the flare gas flow rate using other measurements on platform or facility or a combination of measurement and estimation techniques. These can be combined with process modelling and engineering calculations for determining gas composition, pressure and temperature at key points in the system. By-Difference Calculation Method The by-difference method works on the premise that the gas flared can be calculated from measuring and comparing the other contributing gas streams – i.e. the gas produced minus the gas reused is equal to that flared. If there is a blowdown event, the reading from all of the relevant meters just before this happened can be used to determine the gas flared, although it may be more prudent to use inventory calculations in such instances where known volumes of gas have been vented down the flare. Where there is a dedicated flare gas meter installed in the flare line, the by-difference method can also be used as either a check of the meter results, or as a back-up should the meter signal go out of range or fail entirely. Great care must be taken when attempting to determine flare quantities using the by-difference technique. Whilst it may be suitable for higher flaring cases, and may even indeed be the only option available if the flowmeter has over-ranged, extremely high uncertainty will result when flaring is low. This is due to the fact that the gas flared is calculated as the difference between two much larger numbers causing the uncertainty to “scale up” in relative terms. It can cause gross under- or over-estimation in the flare figure and can even result in falsely negative flare flow rates in the extreme. Inventory Calculation Method - Gas Flowrate The inventory calculation method entails estimating the standard volume of those parts of the system that are blown-down at process conditions. The mass of gas sent to flare can also be determined if the density can be calculated with some degree of confidence. The quantity of gas flared over a period is the difference between the quantity contained in the inventory volume at the start of the process with that at the end. This is calculated using the inventory volume (which can be estimated from geometry or measured at commissioning) and the pressure and temperature measured within it.

NEL


5.2.5 Methods used for Validation and Verification of Flare Metering Systems Calibration and verification of flare gas meters is perhaps one of the most difficult issues associated with the measurement of flare emissions. For this reason, a large proportion of meters are installed without a traceable calibration and the majority will never be removed for subsequent calibration. There are three main options available for calibrating or testing flow meters: 1. Laboratory flow calibration, 2. in situ flow calibration, and 3. Bespoke testing against another meter installed in the system Laboratory flow calibration While there is merit in flow calibrating a flare meter prior to installation it is unlikely that the calibration facility will be able to cover the full range of flowrates, pressures, temperatures and gas compositions found in the flare line (note: the latter may not be as important for some meters). It is much less likely that, once installed, the meter will ever be removed from the test line to be sent back to the flow facility for recalibration. This is due to issues with accessibility, cost and the risks involved pertaining to logistics and installations where the probes are not contained in a meter spool, but rather welded onto an existing length of pipe which cannot be removed from the line. In situ flow calibration, In situ calibrations involve either traversing the flare line to get a bulk average velocity, or gas tracer measurement. Provided they are carried-out correctly, with enough straight lengths of pipe upstream of the measurement plane etc., in situ calibrations have the added advantage over laboratory calibrations in that the meter is being flow tested within its actual piping configuration. Therefore, the calibration factor obtained effectively removes measurement bias due to asymmetrical flow profiles etc., at least for the limited tests done. There are three main approaches for in situ calibration: 1) Traversing using insertion flow meters and gas tracer calibrations using either 2) Radioactive, or 3) Non-radioactive substances. Radioactive tracer techniques are most commonly used on oil and gas facilities as the detectors are non-intrusive – being strapped to the outside of the pipe.

NEL


6 DETERMINATION OF FLARE GAS COMPOSITION Flare gas composition is required in order to determine factors such as mean molecular weight, compression factor (and hence density) and also emission factors. As regards the EU ETS, and other related emissions reporting regimes, the drive in the UK is to determine the CO2 emission factor by a combination of sampling (typically done manually from the fuel gas or lines feeding the flare) and process modelling techniques adopting industry-standard methods. Most flare metering technologies are volumetric and therefore require a measurement of density in order to determine mass flow rate. Therefore, the gas composition must be obtained by secondary sampling methods - the results of which can also be used to determine the emission factor. In principle there are four possibilities for determining the gas composition:

Manual gas sampling and offline analysis by Gas Chromatographs

Automated sampling and offline analysis by Gas Chromatographs

Use of online Gas Chromatographs

Optical spectroscopic techniques All sampling-based systems have issues with obtaining a representative sample from the flare line. It is difficult to obtain a sample at the high flowrates found during process upsets and blowdown events; the higher line pressures evident during such events may compromise safety during manual sampling. Liquids may also be present in the line. 6.1 Manual Gas sampling, with Offline Analysis by Gas Chromatograph Manual sampling involves drawing a sample from a pipeline or vessel into a bag or cylinder for subsequent analysis by GC or other method. It is usually not possible to obtain manual samples directly from a flare line because of health and safety issues - where radiation, explosion hazards and sudden, unplanned surges in gas flow and line pressure can occur without warning. One key issue with manual sampling is the availability of access points and, quite often, line pressures at or below atmospheric levels - particularly under low flaring, where the partial vacuum produced by winds blowing across the flare tip can cause a vacuum. Whether sampling manually, automatically or measuring composition directly, it is imperative that the data is collected often enough in order to effectively track any changes in composition. It is not straightforward to sample from a flare line for a number of reasons:

Sudden changes in flowrate and pressure may present a safety hazard

Obtaining samples during process upsets is difficult since these events tend to be of short duration, infrequent and unpredictable

The sample will not be representative if liquids are present in the line (if not collected and analysed separately)

The vessel and interconnecting pipework must be heated to ensure the entire sample is in the gaseous phase, otherwise errors will occur during the gas chromatography analysis

Since the pressure in a flare will tend to be low, sample pumps or ejectors will likely be required to draw out the sample

The number of purges of the sample bottle (i.e. removal of air) increases with decrease in line pressure

NEL


6.2 Automatic Gas Sampling and Offline Analysis by Gas Chromatograph Whilst such a system has been used to sample process gas, there is no known example of this method being used for flare gas applications. It is possible that automated sampling could be employed only during process upsets and blowdowns, where the composition is more variable and not as well known. Manual samples may suffice for baseline flaring where the gas composition will be more stable. In addition to the general issues with sampling described above, the drawbacks with using an automated sampling system are:

The sample bottle (and the sample frequency) would have to be sized according to the expected frequency and duration of blow downs and process upsets over a given period, and these are unpredictable events

A compressor may be required to increase the effective volume of gas collected to a practical level

Line velocity and conditions during a blowdown may preclude getting a representative sample (although this is also true of manual or online sampling systems)

Pressure will vary from atmospheric during normal flaring, to perhaps as high as 10 bar at the start of a blowdown period, and this will affect the sample volume being collected and could, therefore, bias the sample

The system would likely be expensive to install and maintain (e.g. gas samplers are more prone to leak than oil samplers)

6.3 Online Gas Chromatographs Laboratory-based Gas Chromatographs (GCs) are commonly used to determine the composition from gas samples collected from gas process lines. Online GC analysers offer the ability to determine the gas composition at regular intervals without the need to take samples offsite for analysis. However, online sampling using Gas Chromatographs is currently viewed as impractical in offshore emergency flare lines for a number of reasons:

The time required to obtain an online chromatographic sample analysis is typically of the order of 5 - 15 minutes. Therefore, the sampling system may not have adequate time to react to the resulting change in gas composition during short-lived process upsets.

GC equipment is expensive, requires regular maintenance and skilled personnel to both operate and calibrate it. In addition, bespoke engineering and design will likely be required to enable installation within specific flare applications.

Speciation will generally be limited to the lighter-end hydrocarbons up to C5, although techniques should be able to determine collective C5+ content.

Water, or other liquids, may be present.

Online calibration may be complicated by the number of species present.

Space and access are often at a premium on offshore facilities, but should be less of an issue onshore.

NEL


7 DIRECT EMISSIONS MEASUREMENT TECHNIQUES 7.1 Optical Remote Sensing (ORS) Techniques These techniques utilise the principle that a number of gases absorb light at specific frequencies producing an absorption spectra that forms the basis of the measurement. The magnitude of the absorption peaks is directly proportional to the amount of each gas species in the mixture. Most hydrocarbons, water and CO2 absorb light in the infrared region. There are four main categories of ORS:

Active Open Path – the transmitting and receiving optics are separate, with the

ensuing beam path forming a line of sight through the emission plume.

Passive Open Path - the optics receive light energy from a high energy emissions source (e.g. a hot flare plume) or the sun.

Backscatter – the light beam is aimed at the emission source and light is reflected, absorbed and refracted such that the received light is of lower energy than that transmitted. This method is used in DIAL (Differential Absorption Light Detection and Ranging (LIDAR)) ORS systems.

Mobile ORS – this is basically where a sample is taken from the atmosphere by a mobile vehicle and introduced to an enclosed chamber within which optical sensing techniques are used to determine its composition.

Flare Efficiency Another important factor for refineries and processing plants is the flare efficiency factor for each pollutant. This is needed in order to derive more accurate estimations of emissions of carbon monoxide, particulates (smoke) and unburned hydrocarbons released as a consequence of inefficient flaring. In addition, these facilities produce higher, more complex hydrocarbons, such as BTEX, (Benzene, Toluene, Ethyl Benzene and Xylene) which are particularly harmful to health. It is highly beneficial to have a remote sensing system capable of identifying and quantifying the concentration and migration of these compounds within the atmosphere. Most ORS can only measure a single or limited range of gases with separate optics being required for each target species. In addition, some hydrocarbons produce relatively weak signals making detection more difficult. In other cases interference occurs between components with similar or overlapping absorption spectra Some key ORS methods are OP-FTIR, DIAL, OP-TDLAS and UV-DOAV, and will be applicable to applications as explained below. 7.1.1 OP FTIR Open-Path Fourier Transform Infrared (OP FTIR) spectroscopy is used in a number of commercial instruments and, through its ability to operate over a broad range of wavelengths, has the capability of measuring a number of species simultaneously. It is the most cost-effective ORS instrument in this respect. However the OP-FTIR method is somewhat prone to error where water vapour is present since it has absorption features that overlap those of a number of other gases requiring a skilled user to correctly interpret the data.

NEL


7.1.2 DIAL Differential Absorption LIDAR3 (DIAL) operates using two light beams of differing wavelength, one of which will absorb the target gas and the other which will not be absorbed (so-called “on” and “off” mode). The difference between the signals is proportional to the volume percentage of the target gas within the emissions plume. The beams may operate in the visible or invisible Infrared range. In the past more than one DIAL system was needed to determine multiple species as the frequency of the light beam must be set so as to strongly absorb the target gas. However, it has the longest range of the optical systems (up to 1 km, compared with 250 m or smaller for the other techniques). Newer DIAL systems are being developed that employ tuneable diode lasers, thus allowing for a faster and more complete picture of the emission levels in a tracked plume. However, DIAL is expensive, cumbersome and cannot speciate various hydrocarbons without an estimate of the mole weight. The power usage is high and, therefore, liquid nitrogen is needed to cool the electronics in use. Development of optical technology is ongoing and it is likely that these techniques will be used more in the future for detecting and quantifying flare, vent and other fugitive emissions in the future.

3 Light Imaging, Detection and Ranging (LIDAR) is a remote sensing technology that measures distance

by illuminating a target with a laser and analyzing the reflected light. Doppler LIDAR can be used, for

example, to make detailed measurements of the disturbed wind profile in the wake of a wind turbine.

NEL


8 CONCLUSIONS 8.1 Meter Performance

Flowmeters installed in flare gas lines are generally insertion-type probes that take single-path or single-point measurement; these are more sensitive to flow profile and installation effects than full bore meters.

There is a misconception that an installed flare gas meter will achieve its “out-of-the-box” performance specifications. Under field conditions the meter‟s performance will fall short of this ideal.

The measurement uncertainty in flare gas measurement often deviates significantly from expectations due to installation effects and meter rangeability issues. This is compounded by a failure to identify errors (commonly found at low and high flowrates) in the uncertainty calculation and reporting spreadsheets.

Flare gas applications offer one of the most challenging metering environments with which to determine the uncertainty. A comprehensive approach is recommended – calculating the uncertainty along with the measurement on a point-by-point basis. The data can be compressed by averaging on a daily or weekly basis.

Even though the majority of flaring takes place at very low flow, operators often fail to tune meters into this operating range to maximise accuracy for the region which constitutes the majority of the gas flared over the year.

8.2 Improving Meter Performance

The use of multiple measurement probes or beam paths increases the coverage of the pipe and should result in a better average of the flow profile.

Using more than one meter - each tuned to a different range - could provide improved uncertainty and accuracy over the full operating range.

A combination of calculation and flare gas metering could improve the overall measurement uncertainty for flare gas measurement.

Where possible, operators could make better use of the Speed of Sound feature of the USM to help characterise reservoir composition and support and minimise sampling.

More use should be made of correction factors, which would in many cases greatly improve the measurement uncertainty levels associated with flare gas measurement and remove bias.

Computational Fluid Dynamics (CFD) simulation can prove to be a low-cost and highly flexible tool with which to both characterise installation effects and develop appropriate correction factors.

NEL


8.3 Calculation Methodologies

There is often a misconception by operators and regulators that a by-difference method obviates the need for direct flare gas metering. This is only true during high flaring where the basic numerics of the method are favourable. Even with this, care has to be taken to correct for shrinkage, temperature and pressure effects and uncertainty in estimation of the gas-to-oil ratio, if appropriate.

In many instances it is unlikely that the by-difference calculation method alone would provide sufficient measurement over the full operating range and reporting period. Indeed, it may offer the only solution to “plug the gap” in data where a flow meter fails at high flowrate – or needs to be temporarily taken offline for inspection.

NEL


9 RECOMMENDATIONS FOR FURTHER WORK The key recommendations for further work are:

An investigation into installation effects should be carried out for the most widely used flare gas meter technologies to derive the true measurement uncertainty.

In many cases, a significant proportion of the total gas flared (and, hence, the CO2 released) will emerge from the low-flow end. Therefore, there is a clear need for this region to be fully investigated, focussing on issues concerning: signal resolution, laminar/turbulent transition and temperature stratification.

Meter errors arising from high and low flaring should be investigated and the associated measurement uncertainty accounted for in all calculation and reporting sheets.

There needs to be a methodical and thorough test program investigating laminar-turbulent transition, stratification and installation effects at low velocities in large pipes simulating typically-sized flare lines.

Gas tracer techniques offer a method of assessing flare gas flow meters in situ with the actual upstream pipe configuration and prevailing flow conditions. However, a comprehensive study assessing the technique as employed in flare gas lines is needed to fully assess the capabilities and a realistic uncertainty level in the technique.

Issues relating to the uncertainty in the flare gas composition during process blowdowns should be investigated where it impacts density and emission factor

Optical Remote Sensing technologies – and other direct methods of determining gas emissions - should be further investigated where it may be applied to flare, vent and other fugitive gas emissions in the future.

The most comprehensive approach to investigation of the above issues should ideally take the form of a large, collaborative project involving industry leaders, equipment supplier, regulators and technical consultants where possible.

REFERENCE [1] NEL Report 286/2013 A Review of Flare and Vent Gas Emissions Monitoring and

Reporting Methods - A Comparison of Methods and Approaches Used by Industry Worldwide, June 2013, NEL, East Kilbride, Glasgow, UK.

Documents

A Review of Flare and Vent Gas Emissions Monitoring - · PDF filea review of flare and vent gas emissions monitoring and ... review of flare and vent gas emissions monitoring and reporting