[] TL: A Study of Leakage from the UK Natural Gas Supply System with Reference to Global Warming (GP) SO: Greenpeace UK DT: 1990 Keywords: atmosphere global warming climate change uk europe gas fuels energy greenpeace groups reports gp / [part 1 of 7] Prepared for Greenpeace UK by Catherine Mitchell Jim Sweet August 1990 Earth Resources Research 258 Pentonville Road LONDON N1 9JY 071-278 3833 Acknowledgement The authors wish to acknowledge Dr Tim Jackson for his invaluable assistance with the methodological issues in developing a carbon dioxide equivalent coefficient. We would also like to thank Malcolm Fergusson for his constructive help and criticism during the production of this report. In addition, we would like to acknowledge the assistance of Dr Ben Sweet in explaining the physical properties of gases. CONTENTS Executive Summary 1 Introduction 1.1 The Importance of Methane Leakage 1.2 Development of the Gas Supply Network 1.3 Sources of Information 1.4 Methodology 2 The Chemistry of Methane 2.1 Sources and Sinks 2.1.1 Early Records of Methane 2.1.2 Modern Records of Methane 2.1.3 Isotopic Composition of Methane 2.1.4 Sinks for Methane 2.1.5 Sources of Methane 2.1.6 Future Atmospheric Concentrations of Methane 2.2 Methane in Atmospheric Chemistry 2.3 Complexities of Methane Chemistry 2.3.1 Reactions in High NOx Concentration 2.3.2 Reactions in Low NOx Concentration 2.3.3 Indirect Effects 3 Warming Potentials and the Relevance of Methane Leakage 3.1 Introduction 3.2 Carbon Dioxide Equivalent Coefficients (CDECs) for natural gas, oil and coal 3.2.1 Introduction 3.2.2 Methodology 3.2.3 Natural Gas 3.2.4 Coal 3.2.5 Oil 3.2.6 Conclusion 4 International Natural Gas Leakage 5 Natural Gas Leakage from the UK Distribution System 5.1 Natural Gas Statistics 5.2 The Lengths of High, Medium and Low Pressure Pipeline 5.3 Estimating the Age of the Mains System 5.4 The Distribution of Leakage and Pipe Replacement 5.5 Proportion of Lead Yarn and Mechanical Joints in Medium and Low Pressure Mains 5.6 Conditioners Used on the Distribution System 5.7 Effectiveness of Conditioners in Reducing Leakage from the Distribution System 5.8 Proportion of Leaks at Joints due to Shrinkage Compared to Leakage from Pipelines and Joints due to Fractures and Corrosion 5.9 Reasons for Breakages, Fractures and Corrosion of Pipelines and Joints 5.10 The Breakage Repair Efficiency Rate 6 The Calculation of the Natural Gas Leakage Rate 6.1 The Mains 6.2 Services 6.3 Estimating Leakage 6.4 The Leakage Distribution Curve 6.5 The Effectiveness of Measures to Reduce Leakage 6.6 Conclusion 7 The Issue of Unaccounted For Gas (UFG) 7.1 Meter Inaccuracy Appendix A. A Basic Description of the UK Natural Gas Supply System A.1 Drilling for Natural Gas A.2 Production of Natural Gas A.3 Natural Gas Terminals A.4 Gas Pumping Machinery or Compressors A.5 Pressure Reduction Stations A.6 Storage A.6.1 Seasonal Storage A.6.2 Peak Shaving A.6.3 Liquified Natural Gas A.6.4 Salt Cavity Storage A.6.5 Diurnal Storage A.6.6 Low Pressure Storage A.6.7 High Pressure Storage A.6.8 High-pressure holders A.6.9 Pipe arrays A.6.10 Line Pack A.7 Past-the-Meter and End-use Appendix B Problems of Metering B.1 Introduction B.2 Meter Standards B.3 Meter Accuracy and Temperature B.4 Meter Accuracy and Moisture B.5 Types of Metering B.5.1 Diaphragm B.5.2 Rotary Displacement Meters (RDM) B.5.3 Turbine Meters B.5.4 Orifice Plate Meters B.6 Secondary Instrumentation Appendix C. Domestic Meters Appendix D. Pipelines D.1 History of the transmission and system D.2 Materials D.3 Pipeline Pressure Appendix E. Service Pipes Appendix F. Reasons for leakage from pipelines and means of detection and repair F.1 At Risk Pipelines F.2 Types of Leakage from Distribution Mains and Services F.2.1 Fractured pipes F.2.2 Corrosion F.2.3 Leakage from Pipe Joints F.3 The Reasons for Breakage, Fracturing and Corrosion of Pipelines and Joints F.4 Leakage Detection F.5 Leakage Repair F.5.1 Network Analysis F.5.2 Gas Conditioning F.5.3 Joint Repairs F.5.4 Mains Renewal F.6 Mains Replacement Policy and Effectiveness Appendix G. The Importance of Conditioning Joints G.1 Introduction G.2 Leakage Rate from Joints G.3 The Ability of Conditioners to reduce this Leakage Rate G.3.1 Humidification G.3.2 Aromatic Oil Vapourisation G.3.3 Oil Fogging G.3.4 Internal Vapour Phase Sealant G.3.4.1 Diethylene Glycol (DEG) G.3.4.2 Monoethylene Glycol (MEG) G.3.4.2.1 Flash Evaporator G.3.4.2.2 Sparge Gas Evaporator G.3.4.2.3 Coarse Droplet Separation G.3.4.2.4 Direct Atomiser into the Main G.3.5 Fill and Drain G.3.6 Bridge the Gap Appendix H. Unaccounted For Gas (UFG) Appendix I. Leakage Rates References LIST OF TABLES Table 2.1 Sources of Methane Table 2.2 UK Methane Emissions Table 3.1 Global Warming Potentials. The Warming effect of 1kg of each gas relative to that of CO2 Table 3.2 Global Warming Potentials. The warming effect of an emission of 1 mole of methane relative to that of CO2 Table 3.3 Summary of Constituents of CDECs for Gas, Coal and Oil (kgCO2/GJ) at a Methane Warming Potential of 21. Table 3.4 Summary of Constituents of CDECs for Gas, Coal and Oil (kgCO2/GJ) at a Methane Warming Potential of 63. Table 4.1 International Gas Leakage Studies Table 4.2 Gas Leakage at Production and Supply Phase Table 5.1 Length of UK Transmission and Distribution Mains Table 5.2 Length of UK Mains by Material Table 5.3 Length of UK Mains by Pressure Table 5.4 Percentage Length of Distribution Mains by Pressure Table 5.5 Mains in Use by Year Table 5.6 Mains and services Table 6.1 Leakage Rate from Distribution Mains Table 7.1 Meter Inaccuracy Table 7.2 Leakage Rate Allowing for Domestic Meter Over-Reading Table 7.3 Stock Increase as Leakage Table.A.1 UK Gas Flaring Table A.2 Age of Gas holders Table B.1 Meter Accuracy Table D.1 UK Pipeline Pressures Table E.1 Services in the North West Region, 1976 Table F.1 Pipeline Replacement and Demerit Points Table H.1 Unaccounted For Gas 1962-1967 LIST OF FIGURES Figure 1.1 Percent of 1980s Radiative Forcing Figure 1.2 Environmental Impact: British Gas Figure 2.1 Methane & its Effect on the Planet Figure 2.2 Past & Future Methane Figure 2.3 Methane Sources Figure 3.1 Stabilisation of Atmospheric Concentrations Figure 3.2 CO2 Equivalent Coefficients. British Coal's Methane Emission Estimates Figure 3.3 CO2 Equivalent Coefficients. Deep-mined Coal Methane Emission Estimates Figure 3.4 CO2 Equivalent Coefficients. Gas, Coal and Oil Figure 3.5 Gas Supply System Breakeven Leakage Rates Figure 5.1 Distribution of Mains by Age Figure 5.2 Distribution of Services by Age Figure 5.3 Webb Analysis Diagram Figure 6.1 Leakage Distribution Curves for Services and Mains Figure E.1 Ratio of Service to Mains Reports Figure F.1 Examples of Mains Joints Figure F.2 Examples of Mains Joints Figure F.3 Examples of Mains Joints Executive Summary The largest constituent of natural gas is methane, an important greenhouse gas. As a result of this, even a small leak of methane from the natural gas supply system has a powerful greenhouse effect. At present, domestic and global energy policies commonly advocate switching from coal and oil to natural gas because of its lower carbon dioxide and sulphur dioxide emissions. However, there have been recent suggestions that the magnitude of leakage from natural gas supply systems is such that preferential use of natural gas may be more harmful in terms of global warming than using coal and oil. Clearly, the actual leakage rate from the natural gas supply system is crucial. As a result of our detailed analysis, we estimate that the UK natural gas supply system has a leakage rate within the following range: Gas Leakage Rate (per annum) Emitted Low Case Medium Case High Case Natural Gas 1.9% 5.3% 10.8% Natural Gas 364.4 Mtherms 989.2 Mtherms 2026.9 Mtherms Natural Gas 768.8 ktonnes 2087.4 ktonnes 4276.9 ktonnes Methane 666.0 ktonnes 1808.3 ktonnes 3705.0 ktonnes These leakage rates only include leakage from the distribution pipelines, they do not include leakage from the wider supply system. Because of this, we consider our results to be cautious and that the actual leakage rate is likely to be between the medium and high case. This study finds that if the gas supply system leakage rate is 5.3 per cent of gas consumption then, given a warming potential for methane of 63 over a twenty year period, the impact on global warming from gas leakage is greater than the impact from gas combustion. This study estimates 'break even' leakage rates, at which natural gas has the same carbon dioxide equivalent coefficient per unit of delivered energy as oil and coal, taking a range of methane warming potentials corresponding to different time horizons; Natural Gas Supply System Breakeven Leakage Rates Fuel Methane Global Warming Potentials Breakeven Comparison 20 year time 100 year time 500 year time horizon GWP=63 horizon GWP=21 horizon GWP=9 Gas: Coal 5.3% 11.5% 23.9% Gas: Oil 2.4% 6.95 15.9% There is little data available on methane emissions from the coal industry. If methane emissions from the coal industry are higher than published, then the break even percentage leakage rate of natural gas with coal would also be higher. Calculating a carbon dioxide equivalent coefficient for oil requires detailed information on fuel use and emissions from each stage of the oil industry. Because. much of this information is unavailable it is possible we have underestimated the carbon dioxide equivalent coefficient for oil. Natural gas has a high carbon dioxide equivalent coefficient primarily because the gas distribution system is very old and because conditioning of lead-yarn joints appears so unsuccessful. This situation could be improved if British Gas invested in a new distribution system where the leakage rate would be minimal. If such a program me were feasible then natural gas could then be a preferable fuel, in terms of carbon dioxide equivalent coefficients, to oil and coal. We understand, but have not been able to confirm, that British Gas is carrying out its own investigation of methane leakage from the UK distribution and transmission system. A recent workshop on Methane Emissions, held as part of the Intergovernmental Panel on Climate Change (IPCC), produced findings which were to be sent on to the next stage of the IPCC process. One finding, of relevance to the present British Gas study on methane leakage, stated: "studies need to be scientifically credible, independently performed or independently verified, and subject to public examination." We hope that British Gas will take heed of this recommendation. Only British Gas has access to all the information necessary to estimate an accurate leakage rate. We urge that all reports and studies hitherto undertaken on methane leakage, gas conditioning, unaccounted for gas and meter inaccuracy be made available for public scrutiny. 1 Introduction This study provides estimates of methane leakage from the United Kingdom (UK) natural gas supply system. Natural gas is increasingly said to be a preferable fuel to oil and coal because of its lower carbon content, and therefore lower carbon dioxide (CO2 ) emissions which would be expected to reduce global warming. Low sulphur dioxide (SO2) emissions are also beneficial, from the viewpoint of acid deposition. However, recently fears have been raised that methane leakage from the natural gas supply system, and its accompanying powerful greenhouse effect, may outweigh natural gas's other benefits. Energy policy makers are in a quandary as to whether they should support natural gas in favour of oil and coal or whether they should support oil or coal in favour of natural gas. This study is intended to bring some understanding to this question by examining each step of the UK natural gas supply process in detail so that any area of leakage can be highlighted and, where possible, quantified. There is very little global or domestic information concerning the sources and sinks of methane. This is partly because the realisation of global warming's true significance is a relatively recent development. As a result the majority of research has concentrated on carbon dioxide, primarily because it is the dominant greenhouse gas in per cent terms (see Figure 1.1, page 88). Only very recently has the importance of the other greenhouse gases begun to be considered in detail. In addition, the studies which have been undertaken into methane leakage from the energy industries, whether it be natural gas, coal or oil, have either been undertaken by the industries themselves or by governmental bodies using industry statistics. While the results of these studies may have been questioned, it has been difficult to obtain enough information to carry out an independent study. Our study will be the first in depth investigation, that we know of, which estimates leakage from a natural gas supply industry without depending wholly on industry statistics. This study, by providing an estimate of the leakage rate from the UK natural gas supply industry does go some way to remove a large area of uncertainty. However, it has also highlighted other areas which need urgent research. We estimate that the leakage rate from the UK natural gas supply system is between 1.9 and 10.8 per cent of total throughput. However, to be able to compare one fuel with another we need to have confidence in estimates of methane emissions from the oil and coal industries. We do not have this confidence because the information on methane emissions from those industries is so poor. 1.1 The Importance of Methane Leakage The largest constituent of natural gas is methane, an important greenhouse gas. One methane molecule has a radiative force, on a mole per mole basis, of between 20 to 32 times stronger than a carbon dioxide molecule, although its atmospheric residence lifetime is much shorter. Therefore a small amount of escaped or leaked methane from the natural gas supply system has a powerful greenhouse effect. At present, domestic and global energy policies commonly advocate switching from coal and oil to natural gas because of its lower carbon dioxide and sulphur dioxide emissions per unit of delivered energy. However, it has recently been suggested that methane leakage from the natural gas supply systems may be of such a magnitude that preferential use of gas may be more harmful in terms of global warming than use of coal and oil per unit of delivered energy. Clearly, the actual leakage rate from the natural gas supply system is of crucial importance. It is vital to obtain a realistic leakage rate. It is then possible to compare coal, oil and natural gas by carbon dioxide equivalent coefficients (CDECs) per unit of delivered energy so that an energy policy aimed at limiting the damage of global warming can be achieved. It has been very difficult to obtain independent and verifiable estimates of methane leakage from each or any stage of the UK natural gas supply system. The UK natural gas industry prefers to publicise natural gas's qualities of low sulphur dioxide (SO2) and low nitrogen oxides (NOx) emissions (see Fig 1.2, page 89) rather than release information on methane leakage. According to British Gas, SO2 emissions are 0.73 milligrams per Megajoule (ins/MJ) for natural gas and 48 mg/MJ for low sulphur fuel oil with flue gas desulphurisation and 72 mg/MJ for coal with flue gas desulphurisation assuming 10 per cent of the sulphur remains in the ash (British Gas, 1989) At this point, it should be emphasised that all fossil fuels emit carbon dioxide, although natural gas emits less per unit of energy. None of the fossil fuel industries can claim to be environmentally clean, nor can British Gas claim natural gas to be the 'Earth's cleanest fuel' (Observer, 1 Oct 1989) or the 'least polluting of all fossil fuels' (British Gas, 1989) while it has such a high leakage rate. Equally, it has to be accepted that non-renewable and nuclear energy sources have detrimental effects upon the environment. Only an energy policy based on conservation measures and renewable energy sources can hope to minimise damage upon the environment. 1.2 Development of the Gas Supply Network Natural gas, transported through modern equipment, is likely to be relatively leak free and therefore preferable to other fossil fuels in terms of greenhouse gas emissions. However, the natural gas supply network has been in existence in the UK for 150 years. Parts of it, particularly the low pressure distribution mains that transport natural gas to the domestic consumer, are old and often vulnerable to fracture and breakage. The distribution system also suffers from the after effects of moving from town gas to natural gas. Town gas manufactured from coal contained both aromatic hydrocarbons and water vapour. Lead-yarn joints (50 per cent of the distribution system) were kept tight by the swelling of the yarn from contact with water and mechanical joints (35 per cent of the distribution system) were kept tight by the aromatic hydrocarbons swelling the internal rubber ring. In the mid 1960s town gas began to be manufactured from liquid feed stocks in high pressure reforming plants. The resultant lack of water vapour had a detrimental effect on lead-yarn joints. As the yarn dried out it shrank, increasing leakages by at least a factor of two. When natural gas, totally dry and lacking in aromatic hydrocarbons, was introduced towards the end of the 1960s at a higher pressure the situation was further aggravated. There are, therefore, three main areas of leakage that British Gas has to contend with: leakage as a result of moving from town to natural gas, leakage from the distribution system as a result of break ages, fractures, corrosion or ageing and leakage from the wider supply system. 1.3 Sources of Information The information available from British Gas, other than from its public Annual Reports, has been minimal. Despite several letters to various departments within British Gas and after several Parliamentary Questions have been asked, very little useful information about the workings of the supply system, much less about methane leakage, has been forthcoming. At the end of the day, British Gas is best placed to estimate methane leakage from the UK natural gas supply system. A recent workshop on methane emissions, held as part of the IPCC process, commented on the number of studies which have been published recently. Most of these studies are based on industry statistics. Findings from the workshop, which were to be sent on to the next stage of the Intergovernmental Panel on Climate Change (IPCC) process, recommended that more studies be undertaken and that these studies 'should be scientifically credible, independently performed or independently verified, and subject to public examination'. We very much hope that British Gas will consider these recommendations, discuss this report with us and allow us access to their information so that we can verify their estimate of a leakage rate of around 1 per cent. 1.4 Methodology In principle, leakage from the natural gas supply system should be the difference between natural gas metered in from the rigs and the natural gas metered out from the distribution system. However it is not quite as simple as that. Measurement of a gas is complicated by its physical characteristics; the volume of a gas changes with changes in pressure and temperature. Even if there was a foolproof method of correcting gas to a base pressure and temperature, the accuracy of the meters would also have to be 100 per cent to ensure reliable data. In addition, there are losses from the system due to, for example, pipeline purging and theft. These losses are reported as unaccounted for gas (UFG). This UFG is not necessarily leakage; but on the other hand it is impossible to say it is not. This study is an attempt to quantify methane leakage from the UK natural gas supply-system. We have taken this system to include exploration, drilling and production of natural gas, the pipelines which transport the natural gas from offshore to onshore distribution terminals, the UK onshore transmission and distribution network, service pipes, the pipes in the consumers unit which occur after the meter, and the consumer appliances which may leak because they are faulty. The study does not cover the point of combustion of natural gas. British Gas estimate that around 1 per cent of the natural gas throughput leaks (Shannon, 1990). This estimate refers to leakage from the UK national transmission and distribution system. The National Transmission System (NTS) includes the high pressure transmission pipelines and the equipment plants (such as compressors) which are required to move the gas through that system. The distribution system comprises the low and medium pressure pipelines and the equipment required to move the gas through that system. British Gas's estimate of leakage therefore does not include leakage from exploration, drilling and production or leakage after the meter in the consumers unit, at present the consumers' own responsibility. [] TL: A Study of Leakage from the UK Natural Gas Supply System with Reference to Global Warming (GP) SO: Greenpeace UK DT: 1990 Keywords: atmosphere global warming climate change uk europe gas fuels energy greenpeace groups reports gp / [part 2 of 7] 2 The Chemistry of Methane Methane (CH4) is the most abundant organic gas in the Earth's atmosphere. It has a number of roles in atmospheric chemistry and climate. For example, methane affects tropospheric ozone, hydroxyl radicals and carbon monoxide concentrations, stratospheric chlorine and ozone chemistry and the Earth's energy balance. The evidence that atmospheric methane concentrations are increasing globally is now overwhelming and it is an urgent requirement to understand the processes of methane production; both natural and human. Blake and Rowland (1988) state that globally averaged data between 1978 and 1987 shows an annual increase of 0.016 parts per million per year (ppm/yr), or about 1 per cent per year. Globally averaged methane mole fractions are almost 1.70 ppm. Because of this increase in atmospheric methane concentrations, an imbalance has been caused between the sources and sinks of atmospheric methane. As a result, the atmospheric concentration of methane has increased and is acting as a more and more potent greenhouse gas (see Fig 2.1,,page 90) This chapter is intended to give a simplified account of the sources and sinks of methane and describe methane's role in atmospheric chemistry. Methane's importance to global warming has become more obvious with the recently developed concept of global warming potentials (see chapter 3). Calculation of a global warming potential requires detailed knowledge of methane's chemical life cycle and the indirect effects in atmospheric chemistry. It is hoped that this chapter will provide enough information so that the concept of methane's global warming potential can be understood. This chapter is heavily reliant on Cicerone and Oremland (1988) and on the Scientific Assessment of Climate Change Report to the IPCC from Working Group 1. Readers are urged to turn to those works for a more in depth explanation. 2.1 Sources and Sinks 2.1.1 Early Records of Methane There is good data on the atmospheric concentration of CH4 from Antarctic and Greenland ice cores for the period between 10,000 and 160,000 years ago. The minimum concentration during the last glacial periods (20,000 and 150,000 years ago) was about 350 parts per billion by volume (ppbv). This rose rapidly to about 650 ppbv during the glacial-interglacial transitions (about 15,000 and 130,000 years ago). There is little reliable data on methane concentrations during the last 10,000 years, however. 2.1.2 Modern Records of Methane Ice core data indicates that the atmospheric concentrations of CH4 averaged 700 to 800 ppbv between 200 and 2000 years ago. This increased to 900 ppbv one hundred years ago and has increased since then in step with increasing global population to 1700 ppbv in 1988. This corresponds to an atmospheric reservoir of 4800 Teragrams (1 Tg = 1012g). It is increasing at a rate of 14-17 ppbv per year (40-48 Tg of CH4 per year, or 0.8-1.0 per cent per year (Blake and Rowland, 1988). Atmospheric methane concentration has increased by about 30 per cent over the last 40 years. The atmospheric concentration of CH4 in the northern hemisphere is 1.74 ppmv, compared to 1.66 ppmv in the southern hemisphere (Steele et al, 1987). 2.1.3 Isotopic Composition of Methane CH4 is produced from different sources with distinctive ratios of 12C, 13C and 14C and hydrogen isotopes H, D(2H), and T(3H). The rates of processes which destroy CH4 also depend on its isotopic composition. Cicerone and Oremland, 1988, give a more detailed explanation of this. 2.1.4 Sinks for Methane The major sink for atmospheric CH4 is reaction with hydroxyl (OH) radicals in the troposphere whose abundance is controlled by reactions with CH4, carbon monoxide (CO), non methane hydrocarbons (NMHC), reactive nitrogen oxides (NOx) and tropospheric ozone(O3) (See Figure 2.2, page 91). The reaction between CH4 and OH currently represents a sink-of between 400- 600 Tg per year. The size of this sink has probably decreased over the last century, and continues to do so, because of the increasing abundances of CO, NMHC and NOx. Soils may represent an important sink for CH4 and there have been a number of recent studies on methane uptake from different soils (Whalen and Reeburgh, 1990; Stendler et al, 1989, Megraw and Knowles, 1987). Despite increasing information, there is still great uncertainty as to what percentage of methane produced form leaking pipes would be oxidised by the soil. There is reason to believe that some of the methane leaked from pipes buried in moist soil with an oxygen-exchange would be oxidised. The question that needs to be clarified is what percentage of leaking methane would be oxidised. 2.1.5 Sources of Methane CH4 is produced from a wide variety of anaerobic sources, which are summarised in Table 2.1 below (see Figure 2.3, page 92). Table 2.1 sources of Methane Source Annual Release Range (Tg CH4) (Tg CH4) Natural Wetlands 115 100-200 Rice Paddies 110 25-170 Enteric Animal Fermentation 80 65-100 Gas Supply 45 25-50 Biomass Burning 40 20-80 Termites 40 10-100 Landfills 40 20-70 Coal Mining 17 10-30 Oceans 10 5-20 Freshwaters 5 1-25 CH4 hydrate destabilization 5 0-100 Source: Policymakers Summary of the Scientific Assessment of Climate Change, Second Draft Report to IPCC, 12 March 1990 Table 2.2 UK Methane Emissions Source 1960 1970 1980 1987 KT % KT % KT % KT % Landfill 550 14 550 16 590 16 710 20 Gas Leakage 20 0 60 2 310 9 370 10 Vehicles 10 0 2 0 20 0 20 1 Venting 0 0 0 0 160 4 270 8 Coal Mining 2420 60 0 50 1330 37 1020 29 Cattle 820 20 50 25 910 25 820 23 Other Animals 240 6 25 6 240 7 330 9 Total 4050 100 6 100 3590 100 3530 100 Source: Energy Paper 58, Department of Energy, UK. 2.1.6 Future Atmospheric Concentrations of Methane Future atmospheric concentrations of CH4 are determined by changes in the importance of either sources or sinks (see Section 2.1.4). As the effects of global warming increase, a result of a build up of the greenhouse gases such as methane, there will be changes in temperature and climate which will induce feedback mechanisms. Feedback is the spiralling process whereby as more greenhouse gases are emitted, the greenhouse effect is strengthened and induces more greenhouse gases to be emitted. This induces further greenhouse gas emissions and so the rising spiral of greenhouse emissions continues. The major feedback mechanisms of methane are described below: As CH4 emissions are sensitive to temperature and soil moisture, future climatic change as a result of global warming could significantly change the fluxes of methane from natural wetlands and rice paddies which are the major source of CH4 in the tropics. In addition, the flat tundra regions would also be very sensitive to changes of only a few centimetres in the level of the water table with flooded soils producing 100 times more CH4 than dry soils (Whalen and Reeburgh, 1988). Higher temperatures could also increase CH4 fluxes in high northern latitudes from: 1. CH4 currently trapped in permafrost 2. decomposable matter frozen in permafrost 3. decomposition of CH4 hydrates Quantifying these feedbacks is difficult. For example, it is not known if the thawing of the permafrost would take decades or centuries. 2.2 Methane in Atmospheric Chemistry As described in the earlier part of this chapter, atmospheric methane has several important chemical roles which affect the radiative energy balance of the earth and hence the climate of the earth. In addition, methane may have other far reaching effects, as yet not fully understood, for example its importance to the upper stratosphere temperature and pressure (Robel and Dickinson, 1989). The most important reactant that destroys methane is the gas - phase hydroxyl radical, OH. Methane oxidation produces CQ, CO2, water vapour (H2O), hydrogen (H2) and formaldehyde (CH2O) and it consumes OH (see reaction pathways 1-7 below). The main chemical reactions of methane in the troposphere and stratosphere are the following: They affect tropospheric and stratospheric ozone levels They produce important quantities of H2O in the stratosphere Stratospheric CH4 reacts with Cl atoms to form hydrogen chloride (HCl), a reservoir species for Cl atoms Some of the hydrogen carried upward into the atmosphere in CH4 escapes to space, mainly as H atoms What follows is a very,simplified account of the chemical reactions which a molecule of methane may expect to undergo. Again, Cicerone and Oremland, 1988, give a much fuller description. The first phase of the reaction chain is the production of OH from ozone and water vapour in the presence of ultraviolet light (UV): (R1) O3 + hv --> O(ID) + O2 Then, O(ID), which are electronically excited oxygen atoms, react with nitrogen (R2) O(ID) + N2 --> O + N2 2. ozone is formed in (R3) (R3) O + O2 + M --> 03 + M where M = N2, O2 or any other third body whose collisions stabilise the O3 product. 3. About 1 per cent of O(ID) reacts with water vapour to produce hydroxyl radicals (R4) O(ID) + H2) --> 2OH 4. About 85 per cent of methane emitted into the atmosphere is destroyed by (R5) in the troposphere (R5) CH4 + OH --> H20 + CH3 5. In the stratosphere, most of the remaining methane is destroyed by OH, by Cl atoms and by O(ID) atoms. 6. A small fraction of methane goes through the stratosphere to the mesophere where an additional sink of short wave UV light, (mainly Lyman alpha radiation which has a wavelength of 121.6 nm) destroys methane photolytically. 7. The complete oxidation of methane yields CO2 and H2O (R6) CH4 + 2O2 --> CO2 + 2H2O 2.3. Complexities of Methane Chemistry However, the oxidation of methane is not as simple as (R6) may suggest. In the atmosphere, oxidation is initiated by OH, not O2, and requires light. In addition, methane oxidation and the products which are formed are very different in the cases of high and low concentrations of low nitrogen oxides (NOx). For example the methane oxidation chain can either produce or consume ozone depending on the concentration of nitrogen oxides. 2.3.1 Reactions in High NOx Concentration In the high-NOx columns, as in polluted tropospheric air and all of the stratosphere, methane oxidation produces ozone and hydrogen oxides (HO and HO2). In the first instance the reaction begins with (R5) and after a reaction sequence has the net reaction of (R7) CH4 + 4O2 + 2hv --> CH2O + H2O + 2O3 2. Formaldehyde (CH2O) is oxidised to CO through 3 reaction sequences to have the net reactions of (R8) CH2O + 4O2 + hv --> CO + 2O3 + 2OH (R9) CH2O + 2O2 + hv --> CO + H2O + O3 (R10) CH2O + hv --> CO + H2 3. CO is then oxidised to CO2 in the presence of high NOx concentrations. The net reaction of this is (R11) CO = 2O2 + hv --> CO2 + O3 Therefore the complete oxidation of CH4 in the presence of high NOx produces ozone and, depending on the relative fraction of CH20 oxidised, can produce OH radicals. 2.3.2 Reactions in Low NOx Concentration In large fractions of-the atmosphere NO mole fractions are probably only 10 ppt or less, especially in the altitude range 0 to 6 kilo metres (Ridley et al, 1987, Davis et al, 1987). In these circumstances, methane oxidation consumes ozone and it consumes HOx (OH and HO2) in producing CO2, H2O and H2. Crutzen (1988) estimates that the oxidation of each CH4 molecule consumes 3.5 HOx and 1.7 O3 molecules, while Cicerone and Oremland (1988) estimate less HOx. 2.3.3 Indirect Effects Potentially methane can affect the climate in many indirect ways: 1. Atmospheric oxidation of CH4 produces CO which is converted further to CO2. Cicerone and Oremland (1988) calculate that methane oxidation produces about 8 x 1014g CO/yr. CO molecules survive an average 2 to 3 months before conversion to CO2. In this way about .34 x 10 (15) g C/yr as CO2 is produced globally. Human release of CO2 due to combustion and cement use is about 5.3 x 10(15)g C/yr. As a result Cicerone and Oremland calculate that atmospheric production of CO2 from CH4 is about 6 per cent of the direct annual release of CO2 from anthropogenic sources. 2. Increasing atmospheric CH4 will lead to increased tropospheric O3 and increases in tropospheric water vapour, both greenhouse gases (although the effect of the latter is not yet proven). Resultant tropospheric O3 increases are also able to affect climate, especially if ozone concentrations should increase in the upper troposphere where O3 is a particularly effective greenhouse gas. 3. Methane reacts with chlorine (Cl) to place the Cl atoms in a temporary reservoir. Methane enters the atmosphere after escape from methanogenic wetland soils and rice paddies, mineral exploitation, natural gas distribution systems and from sources such as ruminant animals like cows and sheep. About 85 per cent of total methane flux (Cicerone and Oremland, 1988 estimates 540 x 10(12)g of CH4/yr) is consumed by (R5) with tropospheric OH and oxygen producing CO2, H2O, CO and H2. The remaining CH4, (Cicerone and Oremland, 1988, puts the figure at 60 x 10(12) g/yr) enters the stratosphere. Reaction (R5) with stratospheric OH is the dominant sink, followed by reactions with O(1D) and Cl. (R12) CH4 + C1 --> CH3 + HCl This is a very important reaction in atmospheric chemistry mainly because it places ozone-destroying Cl atoms in a temporary reservoir of HCl molecules that are inactive to ozone (Brasseur and Hitchman, 1988). Chlorine atoms can be released from HCl by reactions between HCl and OH. 4. A small fraction of the H atoms that are released in methane oxidation and from photo chemical decomposition of H2 in the stratosphere escapes to space (Liu and Donahue, 1974). As methane increases temporally it is causing an increase in the rate of H escape to space (Ehhalt, 1986). 5. Because OH is the major sink for atmospheric CH4 and CO, and because these reactions between OH and CO and CH4 suppress OH concentrations there is an instability in the system in that increases in atmospheric CO or CH4 concentrations can lead to a decrease in OH concentration so further increasing the CO or CH4 perturbation (Chameides et al 1977, Sze, 1977). On balance, the present increase in atmospheric methane is probably decreasing OH concentrations (Thompson and Cicerone, 1986, Crutzen, 1987). 6. The direct radiative effect of atmospheric methane also extends into the stratosphere. At altitudes above about 20 kilo metres CH4 molecules act to cool the atmosphere through radiative losses to space (Ramanathan et al, 1985). 3 Warming Potentials and the Relevance of Methane Leakage 3.1 Introduction The importance of estimating natural gas leakage from the natural gas system stems from the fact that methane, the major constituent of natural gas, is a potent greenhouse gas. In spite of the fact that natural gas contains less carbon and therefore produces less CO2, there is a break even point at which the total greenhouse gas emissions from natural gas are equal to the greenhouse gas emissions from coal or oil, depending partly on the rate of leakage of gas and partly on the warming potential assigned to each emitted greenhouse gas molecule. If leakage of methane from the natural gas system is so great that this breakeven point is reached, it is preferable in terms of minimising global warming, to switch away from using natural gas. This is of primary importance to energy policy makers, particularly at a time when most energy policies advocate switching from coal and oil to natural gas precisely because it is thought that natural gas is a preferable fuel in terms of a global warming effect. Until recently, the means of estimating the impact of a greenhouse gas was, in very simplified terms, by multiplying its atmospheric residence time by its radiative force. This, however, does not take account of the indirect effects of the greenhouse gas in the atmosphere. As a means of rectifying this omission, the total impact of a greenhouse gas is increasingly being represented by a global warming potential (GWP) for each greenhouse gas. With the help of a warming potential of a greenhouse gas, a carbon dioxide equivalent coefficient (CDEC) can be calculated for each fuel. The CDEC is calculated by converting the emissions of each fuel into carbon dioxide equivalents so that the greenhouse effect of each fuel can be compared. This is the approach we have taken in this study. A warming potential is dependent on assumptions of the residence times of greenhouse gases radiative forces of greenhouse gases indirect effects of greenhouse gases the time horizon at which the warming potential is assessed The warming potential of each greenhouse gas is found in a consistent fashion achieving a measure which is comparable between gases. Lashof and Ahuja (1990) and Derwent (1990) give very similar definitions of a Global Warming Potential index (GWP): TH o ai(t) Ci(t) dt GWP (i) = ------------------ TH 0 ac(t) Cc(t) dt where ai(t) is the instantaneous radiative forcing due to a unit increase in the concentration of gas i where Ci(t) is the fraction of gas i remaining at time t. where the denominator shows corresponding values for CO2 where TH denotes the time horizon to be taken When a methane molecule is released into the atmosphere it is committed to a life cycle in the atmosphere. As the previous section has tried to make clear, methane is chemically changed into various other molecules and atoms all of which have their own atmospheric lifetimes and radiative forces. A global warming potential figure is therefore a figure which attempts to encapsulate the commitment of each molecule over its own lifetime and the lifetimes of the products resulting from each of the metamorphoses which it undergoes. In effect, therefore a warming potential is based on radiative forces of molecules, residence time of molecules, indirect effects of molecules and the time horizon at which the warming potential is to be assessed. It is important that in order to estimate a break even percentage leakage rate of natural gas, in terms of warming potential between natural gas, coal and oil, all these factors must be known. A correct percentage leakage rate on its own is of no value unless a warming potential of a specified time period, residence time and radiative force are included in the calculation. The means, and input assumptions, whereby radiative forces and residence times are estimated are very complicated. As a result, there are a wide range of estimates for radiative forces and residence times for each greenhouse gas. Essentially, atmospheric chemists estimate the global temperature change induced by a one unit increase in concentration of a greenhouse gas in the atmosphere. Atmospheric residence times for methane have been estimated to be 7-8 years (Khalil and Rasmussen, 1985), 7-11 years (Pearman and Fraser, 1988) 8.1-11.8 years (Cicerone and Oremland, 1988) and 7-11 years (Prinn et al, 1987). In all cases, this is a great deal shorter than the atmospheric residence time for carbon dioxide. There is a wide range reported in the literature for CO2 but it is generally accepted that the residence time is around 100 years. This refers to the residence time of the incremental emissions of carbon dioxide, i.e. those emissions which exceed the ability of the sinks to fix them (Graedel and Crutzen, 1989). Those papers which refer to a shorter lifetime of 3 to 4 years refer to the average time for a carbon dioxide molecule to be fixed by photosynthesis and then re-released to the atmosphere. References to a residence time of up to 500 years refer to the combined lifetime of a carbon dioxide molecule, through the carbon cycle (Weubbles, 1988). The radiative force of methane has also given rise to a wide range of estimates. On a mole per mole basis, methane is estimated to be 20 to 32 times as effective as carbon dioxide in absorbing outgoing long wave radiation. For example, Blake and Rowland (1988) suggest a factor of 20, while Grassl (1989) suggested the far higher value of 32. Table 3.1 Global Warming Potentials. The Warming effect of 1kg of each gas relative to that of CO2 Gas Time Horizon 20 year 100 year 500 year Carbon Dioxide 1 1 1 Methane 63 21 9 Nitrous Oxide 270 290 190 CFC11 4500 3500 1500 CFC12 7100 7300 4500 HCFC22 4100 1500 510 Source: Policy Makers Summary, Report to IPCC from Working Group 1, Second Draft. Table 3.1 is on a weight for weight basis. There has been considerable confusion between warming potentials based on weight or on a mole per mole, or volume, basis. The equivalent warming potentials for methane and carbon dioxide on a mole per mole basis would be: Table 3.2 Global Warming Potentials. The warming effect of an emission of I mole of methane relative to that of CO2 Gas Time Horizon 20 year 100 year 500 year Carbon Dioxide 1 1 1 Methane 22.9 7.63 3.27 Note; Obtained by multiplying Table 3.1 GWPs by 16/44, the molecular weights of methane and carbon dioxide respectively. It is very important when discussing or comparing GWPs that their basis is known. Throughout this paper, we are concerned with global warming potentials on a weight basis because the carbon dioxide equivalent coefficients (CDECs, see below) are based on weight. The chosen time frame causes a significant change in the relative warming effect of a molecule and, as a result, has very important policy implications. As can be seen from the results of our calculations in Table 3.3, taking a-time horizon of 20 years and a warming potential of 63, a 1.9 per cent leakage rate of natural gas is marginally preferable to oil, but not coal. With a leakage rate of 5.3 per cent, oil is preferable to natural gas and with a leakage rate of 10.8 per cent, both oil and coal are preferable to natural gas. This is not so when a 100 year time horizon is taken. In this case, natural gas offers little benefit to oil with the medium case leakage rate of 5.3 per cent Gas and little benefit over coal with the high case leakage rate of 10.8 per cent. Natural gas is always preferable to oil and coal with the low case leakage rate of 1.9 per cent. The choice of time horizon, over which the GWP of a greenhouse gas is calculated, is crucial to energy and environmental policy, because it changes the relative importance of the different gases. Thus, if a short time horizon (of 20 years,, for example) is chosen for methane, the GWP is 63. If a longer time horizon is chosen, then the GWP is smaller. At 100 years the GWP of methane is 21 and at 500 years it is nine. The drawback of using the shorter time horizon is that it may lead to policy decisions which abate short-term warming at the expense of longer term effects. An energy policy based on warming potentials corresponding to a 20 year time horizon would tend to allow a greater warming effect than if calculated over a long time horizon. For example, on a weight for weight basis, one kg of methane equivalent to 9 kg of. carbon dioxide on a 500 year time horizon. Taking the long term time horizon as a basis for policy would mean that up to 9 kg of carbon dioxide would be considered 'preferable' to 1 kg of methane (for a given service). Taking the 20 year horizon this would rise to up to 63 kg of carbon dioxide being 'preferable' to 1 kg of methane. In effect, a policy based on a 20 year horizon rather than a 500 year one would, in this example, favour up to seven times as much carbon dioxide. The shorter the time period over which one equates global warming from greenhouse gases, the greater the inequality over the longer term. Calculating GWPs on a short time horizon illuminates the role of those gases which are likely to have the greatest impact on the short term rate of change of global climate. It is possible to envisage circumstances where it might be necessary to favour the short term, where it could be shown (for example) that the associated short term warming effect might exceed critical rates of change in terms of ecosystem adjustment. Also, it can be argued that progress in the understanding of the carbon cycle suggests the possibility of reducing atmospheric carbon dioxide in the long term. Generally speaking however, it is probably unwise to base policy decisions on predicted short term effects at the risk of engendering increased long term warming. Just how long a time horizon should be taken is not entirely clear. Presumably, estimates of when global warming is likely to become critical would have a strong influence on the optimum time horizon. [] TL: A Study of Leakage from the UK Natural Gas Supply System with Reference to Global Warming (GP) SO: Greenpeace UK DT: 1990 Keywords: atmosphere global warming climate change uk europe gas fuels energy greenpeace groups reports gp / [part 3 of 7] 3.2 Carbon Dioxide Equivalent Coefficients (CDECs) for natural gas, oil and coal 3.2.1 Introduction This study is primarily concerned with estimating the leakage rate from the natural gas supply system. However, we have endeavoured to estimate CO2 equivalent coefficients (CDECs) for the natural gas, oil and coal industries so that we are able to compare the different fuels and discover what leakage rate of natural gas breaks even with oil and coal in terms of global warming potential. There have been several studies which have estimated CDECs of natural gas, coal and oil (Okken and Kram, 1989; Wilson, 1990; Levander, 1989; Abrahamson, 1989; Grubb, 1989). However, all these studies have used estimates of methane-emissions derived from industry sources or extrapolated down from a global basis to a specific country. This may result in underestimation of the natural gas leakage rate, and hence of the CDEC of natural gas. As described below, to calculate a CDEC of a fuel it is necessary to use a residence time, a radiative force and indirect effects (or a warming potential to encapsulate these three factors) and a time horizon at which the CDEC is to be calculated and the emission rates of warming gases released during extraction, refining, distribution and utilization of that fuel. In the light of our investigation of methane leakage rates, we feel confident that we are now in a position to calculate a more accurate CDEC for natural gas in the UK on the basis of the above information. However, it has become clear as we compare our CDEC for natural gas with the CDECs for oil and coal, that the information available for methane emissions from the oil and coal industries is also very poor. As a result we consider that our estimates of the CDECs of coal and oil are likely to be underestimated; and therefore the break even leakage rate of natural gas with coal and oil is also likely to be on the low side. 3.2.2 Methodology A method is clearly needed which can sum and compare the contributions of greenhouse gases emitted from extraction to utilisation of different fuels. One such approach is the carbon dioxide equivalent coefficient. This is a development of the concept of carbon coefficient described earlier in the chapter. In calculating CDECs, greenhouse gases emitted or leaked from each fuel source are 'converted' to CO2 equivalents via their warming potentials relative to CO2. The scope of our study is from extraction to delivery of fuel, plus the carbon dioxide emitted during combustion. Owing to the wide range of combustion efficiencies and conditions of different technologies, the study does not take account of variations in conversion efficiency, nor of the rate of formation of nitrogen oxides, for example. This analysis therefore, provides estimates of CO2 equivalent coefficients of gas, coal and oil in the UK, up to the point of combustion, and including CO2 to be released from combustion. These may then be used to compare specific applications through applying the appropriate values for the thermal efficiencies and including other combustion gases as necessary. Specific uses of fuels should not affect the CO2 equivalent coefficients derived to a great degree. The CDEC of natural gas use is supply specific because leakage rates vary between the different phases of supply. We estimate our leakage rate from the whole of the system averaged over entire gas consumption in domestic, commercial, industrial, and energy industries. Without information on the distribution of leakage throughout the gas supply system it is not possible to provide use specific CDECs; but clearly leakage rates may differ with differences in the nature of the supply. As described earlier, when calculating a CDEC of a fuel, the global warming potential and time horizon must be decided upon. We deal with this range of uncertainty by presenting our results for a range of methane warming potentials between 0 and 84. One can then choose the warming potential that suits the time frame under consideration and the current opinion on the behaviour of gases in the atmosphere. All data on UK statistics on fuel production and consumption are obtain from the Digest of UK Energy Statistics (DUKES) 1987-89. Statistics on methane emissions from the coal industry are provided by the Digest of Environmental Protection and Water Statistics 1989. 3.2.3 Natural Gas For natural gas we use the a CO2 coefficient of 0.43 Gigatonnes per TeraWatt year (Gt/TWy) (Smith, 1988), which is then converted to the more commonly used unit of 50 kilogrammes CO2 per GigaJoule (kgCO2/GJ). Energy use by the gas industry is a significant element in adding to the overall greenhouse impact of natural gas use. The figure given for producer's own use is 1321 million therms (Mtherms) for 1988 (DUKES). Producer's own use is a composite of gas us ed in extraction, refining and pumping operations. If we divide this by the total UK gas consumption figure of 18766 Mtherms (total consumption excluding colliery methane, producer's own use, stock change and adjusted for domestic meter inaccuracy, see section 7.1), this gives us the proportion of producer's own consumption inherent in gas delivered. One possible source of inaccuracy in this figure is that a high proportion of UK available gas is imported (around 20 per cent). Undoubtedly some of the energy use involved with the importation of gas (both from the Norwegian Frigg field and LNG) is included in this figure, but it excludes the non-UK energy use. Without further data on how much the producer's own use figure deviates from the real figure, we assume it does not. There is a further figure for gas industry own use (120 Mtherms) in the statistics covering works, offices and showroom consumption, which is included as end-use rather than a function of supply. For the leakage rate of natural gas from the supply system, low, medium and high leakage rates of 1.9 per cent, 5.3 per cent and 10.8 per cent respectively have been adopted. These are derived from our study of pipeline leakage (see Chapter 6). Note we do not include any estimates of natural gas emissions from extraction operations due to the lack of data available. This may be a significant area of underestimation in our calculation of natural gas CDECs. To convert these leakage rates into a CO2 equivalent coefficient it is necessary to incorporate assumptions of: the proportion of methane in natural gas (which is approximately 86.6 per cent on a mass basis for Mean Bacton Gas) the inverse of the calorific value on a mass basis of natural gas, to convert the figure to the correct CO2 equivalent coefficient units. We thus obtain the following equation: CO2EquivCoefGAS = CO2CoefGAS x (1 + GASPGAs/CGAS) + WPCH4 x CH4/GAS x 1/CVGAS x GASEGAS where subscripts denote the industry superscripts denote fuel P = producer's own use C = UK consumption WP = warming potential CH4/GAS = methane in natural gas (mass basis) CV = calorific value (mass basis) E = emission rate (%) 3.2.4 Coal In this analysis we have adopted a carbon coefficient for coal of 0.75 Gt/TWy converted to a CO2 coefficient of 87.2 kgCO2/GJ. Producer's own use of coal is much lower for the coal industry at only 0.18 per cent (DUKES). The equation is complicated by the fact that 22 Mtherms of colliery methane was used in collieries in 1988 which adds 0.09 per cent to producer's own use of energy. The total production of 51 Mtherms of colliery methane has to be added to the available energy from coal production, but this is only equivalent to around 0.23 Mt of coal. Coal production also involves electricity consumption, but the complexity of modelling the CO2 equivalent for electricity production prohibits us quantifying this element. The level of methane emissions associated with UK coal production is currently the subject of some debate. The UK Department of Environment publishes statistics on emissions of methane from UK open-cast and deep-mining (Digest of Environmental Protection and Water Statistics (DEPWS). For 1988, these are given as 985 kt methane from deep-mining and 7 kt from open-cast mining. When one divides the stated emissions from deep-mining by the output from deep-mines one obtains a figure of 11.8 kt methane/Mt coal or 0.46 kg methane/GJ coal. However, this emission factor is constant over the entire ten year period covered by the DEPWS. This implies that estimates of methane leakage are obtained by applying a uniform methane emission factor across a large time span. Curiously, no account is taken of methane capture from deep mines, which varies considerably over time. Logically, one might expect that total methane emissions would vary broadly as a function of coal production, but that captured methane would be deducted from this total. This does not appear to be approach adopted in calculating methane emission from deep mined coal, however. One can use methane capture data to obtain a methane emission factor for deep-mined coal prior to methane capture. We can call this the generic methane emission factor, as opposed to the 'actual' methane emission factor. If one includes methane capture data to calculate a generic methane emission factor for UK deep-mined coal, one obtains a figure which does not demonstrate the same startling consistency over time as the 'actual' methane emission factor implicit in the Digest of Environmental Protection. It is suggested that if one had to apply constant emission factors they would be better used to obtain a generic methane figure from which capture could be deducted, rather than an 'actual' methane emission figure, as appears at present. These issues must strongly call into question the empirical basis of such data and serve to indicate that there is considerable room for improvement in methane emission estimation techniques currently employed in the UK. One would expect that estimates from open-cast coal are open to similar margins of error. Figure 3.2 (page 94) shows UK coal CO2 equivalent coefficients for open cast, deep-mined, and total coal production with estimated generic emission rates for deep-mined and total coal production. Note that there is no methane capture from open cast coal. Studies suggest that the open-cast emission figure may be exceptionally low (Battino, 1989), and we suspect the UK figure for emissions may be the result of lack of data and a desire to avoid the practical problems which may arise in trying to gather such data. It should also be noted that there exist considerable possibilities for improving methane capture rates from UK deep mines. To put the UK generic deep-mined emission factor into perspective, Figure 3.3 (page 95) shows CO2 equivalent coefficients for UK coal using a range of hard coal deep-mined emission factors (Selzer, 1990, Battino, 1989). These illustrate that official UK methane production estimates (production plus capture) fall well within the range of other estimated leakage rates; but higher values have been suggested. Battino's work is of particular interest since it sets out a range of rates according to type of coal and depth. The low rate is for high volatile bituminous coal at 500 metres, the high rate is for deep anthracite. However, no detailed studies based on this data have to our knowledge been carried out in the UK. The CO2 equivalent coefficient for coal is calculated according to the following formula: CO2EquivCoefCOAL = CO2CoefCOAL x (1 + COALPCOAL) + CO2CoefCH4 x COALPCH4/CCOAL + WPcH4 x 1/CVCH4 x COALECH4 where subscripts denote the industry superscripts denote fuel P = producer's own use C = UK production WP = warming potential CV = calorific value E = emission rate 3.2.5 Oil CO2 equivalent coefficients for oil are a complex matter, given the wide range of products from the oil industry. These include not only different grades of oil from heavy fuel oil to petrol but also associated gases such as butane and propane. Rather than attempt a full study of the UK oil industry we use Grubb's analysis (Grubb, 1989) which gives a central carbon coefficient estimate of 19 kgC/GJ with a additional figure of 2.28 kgC/GJ mainly for producer's own use and flaring. Additionally, we assume that gas venting from oil platforms is equivalent to 5 per cent of gas flared (although in the US, it is stated that 20 per cent of vented and flared gas is released to the atmosphere (Lash of and Tirpak, 1989). This results in a figure of 0.15 per cent of energy output of the oil industry as vented natural gas. This is most probably an underestimation of the true methane emission rate from oil production operations, and this area clearly needs more research. We thus obtain a CO2 equivalent equation for oil of: CO2EquivCoef = CO2CoefOIL x (1 + OILPOIL/COIL) + WPCH4 x CH4/GAS x 1/CVGAS x OILECH4 where subscripts denote the industry superscripts denote fuel P = producer's own use (including all additional CO2) C = UK consumption WP = warming potential CH4/GAS = methane in natural gas (weight basis) CV = calorific value E = emission rate 3.2.6 Conclusion These calculations provide CO2 equivalent coefficients for oil and coal, and three coefficients for gas at different leakage rates. These are represented in Figure 3.4 (page 96) for the 0-84 range of methane warming potentials. They are summarized in table form below for a methane warming potential of 21 and 63, corresponding to recent draft IPCC figures for 100 and 20 year periods respectively (Policy Makers Summary, Second Draft 1990, Table 3.1). Table 3.3 Summary of Constituents of CDECs for Gas, Coal and Oil (kgCO2/GJ) at a Methane Warming Potential of 21. (Omitted .. unscannable) Table 3.4 Summary of Constituents of CDECs for Gas, Coal and Oil (kgCO2/GJ) at a Methane Warming Potential of 63. (Omitted .. unscannable) Referring to Figure 3.4, the left hand axis shows CO2 equivalent coefficients at a methane warming potential of zero. This is equivalent to assuming a zero methane emission rate. The gradients of the curves on the graph are determined by methane emission rates as a function of methane warming potentials. The extreme right of the graph illustrates axis shows CO2 equivalent coefficients assuming a methane warming potential of 84, which is that given by Derwent (1990) for a twenty year time span. One striking result of our analysis is that for a methane warming potential of 63 over a 20 year time horizon (Policy Makers Summary, 1990) the greenhouse impact from gas industry leakage is higher than the impact from the release of CO2 during combustion of the gas itself (ignoring combustion specific greenhouse gases such as NOx) (see Fig 3.4). The true CO2 equivalent coefficient curves for natural gas may be significantly higher than shown here when allowance is made for gas emissions during extraction, accidents, sea-bed pipelines, and miscellaneous on-shore leakages. Values for these items reported by industry are shown in Table 4.2, although this data is likely to err on the low side. Other things being equal, Figure 3.4 illustrates that for our medium estimate of 5.3 per cent gas leakage, oil has less impact on global warming above a methane warming potential of 27. Gas is seen to have a lesser impact than coal for a 5.3 per cent leakage rate, although this advantage disappears at higher methane warming potentials. The uncertainty surrounding the coal methane emission rate should not be overlooked in making these comparisons, however. Figure 3.5 (page 97) uses the above results to compare the relationship between leakage from the gas, oil and coal supply industries at a range of leakage rates and methane warming potentials. This is useful due to lack of agreement on warming potentials and appropriate times scales. 4 International Natural Gas Leakage There have been several studies of methane leakage from assorted natural gas distribution systems. However, the vast majority of these studies, Wallis (1990) being the exception, use statistics supplied by the government of the country or the distribution company concerned. One of these produced by the Alphatania group summarises the official statistics from 13 countries. These figures are set out in Table 4.1 below. Table 4.1 International Gas Leakage Studies (Omitted .. unscannable) Cedigaz (1988), published an estimate of global natural gas production, by country, in 1987 which includes a section on 'other losses'. These figures are also widely used but again they are based on official statistics and also do not differentiate between 'other losses' and leakage. There have been a number of other studies, the results of which are listed in Table 4.2 below. In addition to these studies, three studies have given a total leakage figure without breaking it down by phase of supply. DGMK (1989) give a total leakage figure of natural gas from the oil and gas industries of 0.16 per cent; ICF Incorporated quoted 0.8 per cent of total US production and the Pacific Gas Table 4.2 Gas Leakage at Production and Supply Phase (Omitted .. unscannable) Of these studies in Table 4.1 and Table 4.2 only Abrahamson and Wallis estimated the natural gas leakage rate as a first step in comparing the global warming effect of different fuels. Abrahamson (1989) carried out the first detailed study of methane leakage and kicked off the debate about the relative merits of natural gas versus other fossil fuels in relation to global warming. He, however, did use official statistics. In addition, he accepted an average figure of 'unaccounted for gas' as his estimate of leakage. In his analysis he assumes 0.13 per cent of natural gas as being vented (Annex III, Page 5), about 0.54 per cent unaccounted for by interstate gas pipelines (Annex lV, Page 6) and 1 to 6 per cent as lost and unaccounted for by natural gas distribution companies. Most distribution companies report a figure between 2-3 per cent, however, for UFG. He also stated that: "the total US leakage is around 2.87 per cent plus the gas known to have been released to the atmosphere during construction, repairs, purging, and the like, and leakage at the point of natural gas end-use" (Annex lV, Page 8) and: "natural gas leakage rates are consistent with direct measurements of methane concentrations in urban ambient air. These analyses suggest the amount of methane are equivalent to between 2.9 and 5.9 per cent of US natural gas consumption" (Page 1) He concluded that: "if more than 0.5 per cent to at most 2.9 per cent of the natural gas leaks... allowing for the full range of involved parameters...the total greenhouse effect from burning natural gas exceeds that from burning heating oil" Wallis (1990) of the University of Wales has estimated a possible leakage rate of between 3 to 10 per cent of total production in the UK. He comes to this conclusion by attributing 1 to 5 per cent leakage from sea based operations and 2 to 5 per cent for leakage from the low pressure delivery system. However, he cites no supporting evidence for these estimates. From these leakage rates, using a radiative force of 25 for methane and residence times of 10 and 7-20 years for methane and carbon dioxide respectively, he estimates that the relative greenhouse effects of Ggas : Gcoal = 0.95 : 4.1. By this he means that gas has a 0.95 to 4.1 times an overall impact on global warming as coal. By contrast, British Gas maintains that the present rate of methane leakage from the UK natural gas transmission and distribution system is 'around 1 per cent of total throughput' (Shannon, 1990). In conclusion, it is clear that the majority of studies of methane leakage from the natural gas supply systems have either been undertaken by the industry or by groups who have used industry statistics. It is also clear that the results of these studies, with the exception of Wallis, show very low leakage rates. A recent workshop (EPA/EAJ/USAlD, 1990) on methane emissions noted that: "prior to the last few years published estimates of global methane emissions from oil and gas systems have relied on estimates of 2 to 4 per cent leakage. These figures were found by assuming all unaccounted for gas (UFG) was emitted to the atmosphere." In addition, the workshop noted that recent studies had found that methane emission rates from US, Canada, Japan and Western Europe, with the possible exceptions of some countries that rely heavily on old gas systems, may be much smaller than previous estimates. The workshop agreed that "a combination of actual atmospheric measurements and accounting and engineering studies are needed to validate the improved estimates. These studies need to be scientifically credible, independently performed or independently verified, and subject to public examination." These workshop findings were sent on to the next stage of the Response Strategies Working Group IPCC process. While this study cannot comment on all the various studies reviewed here, we have investigated the British Gas supply system in detail. Our estimates are far in excess of British Gas's published estimates. This leads us to question the validity of the results of other studies based on industry statistics. We cannot be sure of the true extent of methane leakage from natural gas supply systems or total global methane emissions until all studies are open to public scrutiny, as called for above. 5 Natural Gas Leakage from the UK Distribution System At all parts of the natural gas supply system, from exploration and drilling through to end-use, there are several possible areas for leakage. In this study we have looked at the supply system in detail. The fact that we have not estimated leakage from most areas of the supply system does not mean that we think there is no leakage. Due to the difficulty in obtaining verifiable information, however, it has not a ways been possible to make reliable estimates. Estimated leakages gleaned from other studies for different areas of the supply system are listed in Table 4.2. Many of these estimates are likely to be conservative. The areas of possible leaks are : Drilling Production Onshore Reception Terminals Compressor Stations Pressure Reduction Stations Storage Pipelines Pipeline Purging Past-the-Meter End-use The calculation of leakage from the distribution system is found in Chapter 6. Anecdotal evidence on leakage rates during production and from compressor stations, low pressure gas holders and pressure reduction stations are found in the relevant section of Appendix A. A detailed description of the workings of the supply system is found in Appendices A to H. 5.1 Natural Gas Statistics There are 3 main sources of natural gas supply statistics for the United Kingdom: The Digest of United Kingdom Energy Statistics (DUKES), the Brown Book and British Gas's Annual Reports. Consistent and continuous series of information are hard to obtain because of the changing structure of the gas distribution industry. Prior to 1949, gas was distributed by a variety of private companies, over 1000 in number. Between 1949 and 1972, gas was distributed by 12 regional boards. From that point until 1986 gas was distributed by a nationalised British Gas, made up of the 12 regional boards. Since 1986, British Gas has been in private hands. In order to establish the total leakage rate, it is necessary to answer each of the following questions: What proportion of the present system was in use in 1969 What proportion of the 1969 system is high, medium and low pressure pipelines What is the distribution of leakage rates in the 1969 system What is the effectiveness of the pipe replacement program me in locating areas of high leakage What proportion of the 1969 leakage occurs from joint shrinkage or through fracture, breakage or corrosion of pipelines and joints What proportion of the 1969 high, medium and low pressure pipelines have lead-yarn and mechanical joints What percentage of medium and low pressure pipelines are conditioned What are the percentage efficiencies of the conditioning which occurs on medium and low pressure pipelines What is the breakage repair efficiency rate In the sections which follow, these questions are addressed in turn. 5.2 The Lengths of High, Medium and Low Pressure Pipeline The British Gas Operating Statistics include the following information annually: Table 5.3 Length of UK Mains by Pressure Type of Mains Lengths of Mains 1988 1989 (thousands (thousands of miles) of miles) Distribution mains 138.8 141.1 Transmission mains Regional 7.8 7.8 National 3.4 3.4 TOTAL 150.0 152.5 There are a few other references in the literature to mains material and its percentage of the system, national or regional: Table 5.2 Lengths of UK Mains by Material (Omitted .. unscannable) Marris (1977) also gives the following information: Table 5.3 Length of UK Mains by Pressure Type of Mains Pressure Mains Per Network (km) Cent High Pressure Transmission >7 bar 963 3.6 Intermediate Pressure 2-7 bar 80 0.3 Medium Pressure 75 mbar - 2 bar 2200 8.2 Low Pressure <75 mbar 23571 87.9 TOTAL 26841 100.0 In addition, King (1977) stated that "the low pressure-system, mainly of cast iron, is 80 per cent of the whole". He added that the whole system was 200,000 km in length, and therefore the low pressure system would be 160,000 km. Finally, Corcoran and Argent (1985) stated that 89 per cent of high pressure system was 15,000 km in length (16854 km = 100 per cent, by our calculations) and that 12,000 km of medium and low pressure system was made of steel. This does not agree with the other figures, however. The North West Region appears to have a very high proportion of cast iron and low pressure system and a very small medium pressure system. We have decided to adopt King's lower figure of 80 per cent low pressure pipe work. Therefore we conclude that in 1988 the length of the transmission and distribution system could be broken down by the percentages given in Table 5.4 into different lengths of high, medium and low pressure pipelines. Table 5.4 Percentage Length of Distribution Mains by Pressure Pressure Percentage of Distribution System Low 80.0 Medium 12.5 High 7.5 A. Estimating the Age of the Mains System British Gas (1984) published the following miles of mains in use: Table 5.5 Mains in Use by Year Year Mains in Use (1000s miles) 1882/3 17.6 1891 22.2 1901 27.8 1911 36.7 1921 39.5 1931 51.8 1941 67.4 1951 77.4 1961 97.3 1971 123.5 1979 138.0 1981 141.8 1982 142.6 This does not take account of the number of miles of main that are abandoned or replaced each year. Therefore, it is impossible to say that of the 142.6 miles of the mains in use in 1982, 17.6 are older than a hundred years, for example British Gas publishes the following statistics in their annual report: Table 5.6 Mains and services (Omitted .. unscannable) In order to estimate the age of the mains system it was necessary to go through the annual reports of each regional board. These generally report the amount of new mains laid and relaid and services laid or relaid from 1949 to 1971 (see Figure 5.1 and Figure 5.2, page 98). We have based our leakage rate on Pickering et al's (1970) average leakage rate on the 1969 low pressure system. To apply this leakage rate, we needed to know what percentage of the current system was in use in 1969. On this basis of the available data, we concluded that 61 per cent of the current mains distribution system was in place in 1969. We have assumed that British Gas has always repaired or relaid the leakiest mains first which is a 'best case' assumption. This 61 per cent figure takes account of the King Report which recommended in 1977 that the most hazardous (as compared to leakiest) sections of main be replaced by 1984. King (Clause 93) states that at least one region of British Gas expects to have all small diameter cast iron mains replaced (most laid prior to 1953) in the more hazardous locations by 1984. This represents about 8 per cent of the total low pressure mains of the region. He added that a similar program me to replace medium pressure pipelines in the "more hazardous locations is also in hand". In clause 93 he stated that a programme to replace "higher risk priority mains" by 1984 formed a reasonable minimum time scale. He also concluded in clause 94 that "the wholesale replacement of mains even in areas of relatively high risk cannot be justified on economic ground". In our judgement, it is fair to gather from this that King felt that around 8 per cent of low pressure cast iron mains were hazardous as opposed to leaking in a non-hazardous way. We have not been able to discover from British Gas whether King's recommendations have been carried out, however. We understand that there has been a follow up report to King (1977) which is known as 'King 2', but we have not been able to obtain a copy. B. The Distribution of Leakage and Pipe Replacement Having ascertained the level of pipe replacement one then has to estimate the distribution of leakage rates around the average. Clearly the larger the ranges of leakage values within the sample, the larger the possible impact of a pipe replacement program me (see Section 6.4). C. Proportion of Lead Yarn and Mechanical Joints in Medium and Low Pressure Mains The medium and low pressure distribution system has been constructed over the last 150 years. Prior to the introduction of natural gas in the late 1960s the pipelines had been built to carry town gas. Town gas contained water and oily compounds which swelled the rubber seals of the mechanical joints and the yarn of the lead-yarn joints. With the move to the dry and oil free natural gas these mechanical and lead-yarn joints shrank causing leakage. For a fuller explanation of joints, refer to Appendix F. It has proved difficult to find successful sealants or conditioners for lead-yarn joints which can be carried by natural gas through the distribution system (see Section 5.6). Lead-yarn joints continue to leak more than mechanical joints. This may only be hearsay since there is no available evidence of successful conditioning of mechanical joints. To the contrary, Robinson (1986) describes severe problems undergone by the East Midland region over a period of 12 years; a 6 km stretch of medium pressure, mechanically jointed pipeline continued to leak despite continued attempts to control it (see Section F 4.3). However, allowing for successful conditioning of mechanical joints, we need to know for our leakage calculation what proportion of the distribution system is made up of lead-yarn joints. King (1977) stated that 50,000 km of pipelines accounted for 60 per cent of lead-yarn joints in the distribution system (83,333.3Km = 100 per cent). In 1977 we know there was 4523 km of high pressure transmission line (Brown, 1983), so that at that time medium, low and intermediate pressure pipelines totalled a tenth of 195,000 km. Lead-yarn joints were therefore used in around 43 per cent of the total length at that time. Pickering (1970) stated that of an estimated total 41 million joints in the distribution system, 23.5 million were lead yarn and 15 million were mechanical, comprising 57.3 and 36.6 per cent respectively. The only other reference we have been able to find is that of Bennett and Richards (1983) who stated that more than 50 per cent of the joints in the East Midland Gas Region (Emgas) distribution system were lead-yarn at that time. In conclusion, we consider it a conservative estimate that 50 per cent of the low and medium pressure distribution system in 1970 was jointed by lead yarn joints. [] TL: A Study of Leakage from the UK Natural Gas Supply System with Reference to Global Warming (GP) SO: Greenpeace UK DT: 1990 Keywords: atmosphere global warming climate change uk europe gas fuels energy greenpeace groups reports gp / [part 4 of 7] D. Conditioners Used on the Distribution System Conditioners are the substances which are added to, and travel along with, natural gas in the distribution system. There are many sorts and a full explanation of them and how they are used is given in Appendix G. The main conditioners are distillate, used for mechanical joints, and diethylene glycol (DEG) and monoethylene glycol (MEG) used for lead-yarn joints. E. Effectiveness of Conditioners in Reducing Leakage from the Distribution System In order to calculate a leakage rate from lead-yarn joints, we need to know how many lead-yarn joints are conditioned and how effective the conditioning is in cutting down leaks from these joints. DEG proved to have limited travel at the low velocities obtained in the low pressure system and trials showed that significant travel of DEG in fog form could only be achieved in the medium pressure mains. Despite its limited use, DEG sealing was positive but very slow. As a result DEG was superseded by MEG which had 10 times the vapour pressure of DEG and therefore was able to have greater vapour phase concentrations (King, 1977). MEG was also more effective than DEG. Crompton (1980) showed that the effect of MEG on dry, new yarn gave an average reduction in leakage of 84 per cent when air was saturated to 55 per cent MEG. In other laboratory tests which examined the effects of humidification followed by MEG (but did not state the saturation level), Crompton showed that the leakage rate dropped by 78 per cent. When natural gas, 100 per cent saturated with MEG, was passed over old yarn joints, leakage rates fell by 70 per cent after 600 days. These figures were supported by Arnold (1984). We can conclude that MEG can reduce leaks by 70-84 per cent, depending on the age of the yarn, but only if the natural gas has a high enough saturation rate. This seems less certain. Crompton reports that in 1980 the progress the regions had made in implementing MEG conditioning varied. He stated that the 4 or 5 regions (out of 12) that were conditioning a large proportion of their gas reported encouraging evidence of reduction in leaks. However, he also reports that the national average trends of gas conditioning in 1978-9 with MEG were between 30 and 40 per cent of distributed gas. This was a rapid rise from 1976-7 due to increased equipment installation. But as he pointed out, the projected expenditure on new conditioning equipment was flat until 1981/2. We can assume from this that the national average saturation figure of distributed gas was 36 per cent in 1978-9 and unlikely to rise above this level. So, although we know that 36 per cent of the network was being conditioned at the high-medium pressure input point we do not as yet know how much of the low pressure system was being conditioned. Bennett and Richards (1983) state that with real effort they had been able to achieve an average of 21 per cent MEG saturation at the extremity points of the East Midland Region. Arnold states that because the low pressure gas velocities are low they are unable to carry the MEG vapour droplets very far - about 400m from cold MEG atomisers and 800m from sparge MEG atomisers. High levels of effective conditioning are obviously very hard to achieve. But for conditioning to work, a joint must be conditioned solidly for at least 2 years to achieve maximum benefits. Saturation must be at least 50 per cent to achieve a significant improvement in leakage and at least 25 per cent to maintain the ground that has been gained (Arnold, 1984). There are many factors which effect conditioning efficiency, described in detail by Arnold. The most important factors are; firstly residual DEG from past conditioning programmes will absorb MEG and make MEG ineffective. Secondly, the saturation of natural gas depends on the temperature. If natural gas is saturated with MEG at a low temperature and then the gas warms up (and expands in volume) the percentage saturation of the gas decreases. Thus the effectiveness in conditioning decreases. The point to remember is that if conditioning fails mechanical and lead-yarn joints will leak. A major problem, when trying to understand how effective the different conditioners have been, is the lack of information available. There have been 5 or 6 papers (Pickering, King, Crompton, Bennett and Richards, Arnold and Clough) but they have appeared over a 20 year period, and the technologies have changed over this period in time. The most up to date paper on the subject does not give much confidence in the ability of the gas industry to reduce leakage from joints. Clough (1989) stated of the conditioning program me in the North West Region prior to 1988 that it was 'manifestly obvious that the levels of conditioning agents reaching the periphery of the low pressure network were inadequate to cause effective conditioning'. He also stated that there was a tendency to neglect conditioning between 1983 and 1985. Clough does give a glimmer of hope with a new conditioning process known as WISE spraying, which sprays MEG directly into the low pressure main. In field results, North West Gas looked at 1.5 km of 4 inch diameter leaking lead yarn jointed main where over 43 indications have been recorded. Comprehensive MEG spraying through 16 stand pipes at optimum rates resulted in 80 per cent improvement in a week with 4 indications remaining after 2 weeks. Of these 4, 1 was a fracture and 3 were services. It is hoped that this process will soon be very widely in use. In conclusion, in order to calculate leakage from the medium and low pressure distribution system we need to know what percentage of the joints, which will leak simply as a consequence of moving from town to natural gas, have been conditioned and how effective that conditioning has been. As can be seen from the preceding discussion it is a very complex area and the effectiveness of conditioning will depend on a number of factors. Given the paucity of information, we have estimated a high and low leakage rate figure which corresponds with low and high conditioning respectively. It seems fair to say that before 1987, complete saturation was achieved in no more than an average of 30 to 40 per cent of the natural gas throughput. Even if this figure was higher in special cases (as with Clough's data showing 90 per cent full saturation) the low pressure extremities are only between 30 and 40 per cent fully saturated. We have assumed for our low leakage rate that 100 per cent of natural gas throughput from the high to medium pressure mains is fully saturated with MEG and that it reaches 30 per cent of the periphery low pressure mains. Our high leakage rate is based on the assumption that only 30 per cent of the natural gas throughput at the high-medium pressure input is 100 per cent saturated by MEG. Our medium leakage rate takes the half way point between these two levels. These assumptions are likely to minimise leakage. We have assumed an 84 per cent effectiveness in reducing leakage. 5.8 Proportion of Leaks at Joints due to Shrinkage Compared to Leakage from Pipelines and Joints-due to Fractures and Corrosion. Most of the available literature, when discussing leaks from mains, talks generally about leaks from mains, (for example Pickering), without differentiating between the proportion of the leaks from pipelines and joints due to break ages, fractures or corrosion and leakage from joints as a result of the effects of moving from town to natural gas. In addition, most of the literature which discusses the minimisation of those leaks concentrates on conditioning and its effectiveness of reducing leakage from lead-yarn and mechanical joints. However, it is very important to remember that leakages from fractures and break ages constitutes a large proportion of the total leaks and that conditioning is unable to reduce that leakage. For our calculation of leakage, it is necessary to attribute leakage rates due to joint shrinkage or from pipeline and joint break ages. We can then estimate how much of our total leakage is from joint shrinkage and then what proportion of leakage can be reduced by conditioning. Marris (1977) states that in the North West Region, of all incidents caused by failure of the distribution system, 73 per cent arise from mains of which 55 per cent are fractures and 27 per cent arise from services. Of the services, 95 per cent of the failure is caused by corrosion. Davenport et al (1972), writing very early on in the changeover from town to natural gas reported that in the North Western region nearly 70 per cent of total leakage occurs in low pressure networks. During 1971-2, some 70 per cent of detected and repaired leaks on mains were at joints. He does not, however, specify what proportion of this 70 per cent was due to joint packing shrinkage or due to breakage, nor does he specify what proportion of the gas throughput is natural or town gas. We can agree that at least 30 per cent of the detected and repaired leaks on mains were in the pipelines. In conclusion, we have taken 45 per cent, 57.5 per cent and 70 per cent leakage as a result of joint shrinkage (and therefore open to reduction through conditioning) as our low, medium and high leakage factors. G. Reasons for Breakages, Fractures and Corrosion of Pipelines and Joints Pipelines and joints break, fracture and corrode due to several factors, the most important being: the pipeline or joint material, sub-soil the pipeline is laid in, climatic factors such as rainfall or drought, proximity to human interference such as mining and increased traffic loads. Surprisingly, age in itself, rather than the above factors, does not give rise to significant break ages or fractures (Marris, 1977, King, 1977, Proudman, 1987, see Figure 5.3, page 99). For a fuller description of the reasons why pipes and joints break, turn to Appendix D. H. The Breakage Repair Efficiency Rate The breakage repair efficiency rate is intended to reflect British Gas's ability in finding and reducing leakage from breakage, corrosion and fracture throughout the distribution system. There is very little information available on this question. There are, however, some very serious indications of the problem of break ages or fractures. For example one extreme is: "indications of the problems faced in areas affected by mining subsidence can be seen from a district containing 900 consumers, 673 hectares (2.6 square miles) in area, where 1,100 incidents of broken mains and services we experienced over a period of 5 years on 3,290 m (3600 yards) of main" (Handrihan and Martin, 1973). Another worrying example is that describing the efforts taken to repair a 6.2 km, medium pressure distribution line near Doncaster which was made up of 1230 stavely spigot and socket flexible joints. Over the 12 years to 1983, 135 joints had been rebolted or encapsulated. When a flame ioniser method (FIM) tested for methane leakage from the pipeline in 1983, 26 indications-(points of leakage) were found. However, eventually after 12 months work all joints were sealed, reducing leakage 100 per cent (Robinson, 1986). In addition to these worrying, but admittedly probably rare, cases are the severe problems experienced in mending breaks or fractures by such means as pipe repair clamps or split collars (Ayres, 1988). No specific figures or estimates are given for, what she describes, as the 'unsatisfactory' nature of the means of repair. Ayres states that 35,000 of these unsatisfactory clamps and collars were used, at least until 1988, every year. New clamps and collars are being developed which allow better attachment to mains, thus reducing leakage. It would seem, therefore, that there are severe problems of leakage from joint and pipeline breakage, that clamps and collars do not always provide a complete reduction in leakage and that it may take years, after discovery of leakages, before the leak is reduced by 100 per cent. The only other relevant information gleaned from the literature is from Clough, 1986, who describes anaerobic sealing of joints as 'near 100 per cent efficient' and from King, 1977, who reports that 98 per cent of public reported incidents are usually reached within an hour. However, no information is available to describe what proportion of the leakage from break ages is discovered. We therefore have no real information which describes the breakage repair efficiency rate. To be very cautious we have assumed a 90 per cent efficiency for our low leakage case, 85 per cent for our medium leakage case and 80 per cent for our high leakage case. I. The Calculation of the Natural Gas Leakage Rate The following information was used to calculate the total leakage per annum from the distribution pipelines. A. The Mains Age of pipelines was estimated as described above using figures for total mains in use, new mains and main relaid. These three categories of data are essential in order to estimate ages of pipelines. Prior to 1964 we have the individual regions annual reports as a basis for our estimates. We made two assumptions in creating the aggregate statistics from available data: where there was a year missing in the data, we assumed it to be an average of the prior and following year. where there was a type of data missing (for example, 'Mains Relaid' is missing from the South Eastern Board accounts) we assumed it to be equal to the appropriate average figure for the known part of the system. This gives us a reasonably accurate account of the growth and replacement of the supply system from 1948 to 1988. To make an estimate of the age distribution of the mains system at different times, one has to make an assumption about the age of the pipes replaced. We therefore chose to assume that British Gas always replaced the pipes from the pre-1970 system, we go on to develop assumptions about which pre-1970 pipes are replaced below (see Section 6.4). Given that we only use data on leakage from the pre-1970 supply system, then to assume that all pipe replacement is from that part of the present system is the most favourable assumption one can make given the lack of information. From this analysis we derived the age distribution of mains pipes illustrated in Figure 5.1 (page 98). The methodology employed for the service system was similar to that used for estimating the age of the mains. However, there is even less information available in this instance. Two main problems present themselves: It is necessary to establish the number of services, services relaid and new services for each years. In cases where this information was not reported by a regional board, we assumed that the number of customers was a reasonable proxy for the number of services in use. It is necessary to estimate the length of services from the number of services. There is very little data available on this at all. Marris (1977) gives a total length of services in the North West region as 23,395 km for 2,070,403 customers in 1376. From this we deduce an average UK service length figure of 0.0113 km. We again assumed that British Gas replace the pre-1970 services first which gives us the age distribution graph for services shown in Figure 5.2 (page 98). It can be seen that the replacement rate for services appears to have been higher than for mains. As a result we appear to have a more modern stock of service pipes than mains pipes. C. Estimating Leakage Information on average leakage rates per mile or kilometre from mains is extremely scarce (see Appendix I) The Gas Council published a report by Pickering et al (1970) which studied the problem of gas leakage in low pressure mains associated with conversion from town gas to natural gas. Their study of 1330 km of mains pipe gave an average leakage of 0.67 m3/hour/km at a pressure of 15 mbar. Pickering estimated that the leakage rate would at least double after conversion to natural gas due to the shrinkage of joints due to drying out. Also the fact that natural gas has to operate at twice the pressure of town gas would lead to a further doubling of the leakage rate. This means that the town gas leakage rate of 0.67m3/hour/km should be multiplied by at least a factor of 4 (on a volume basis) to obtain leakage rates for natural gas. In addition, Pickering et al noted that leakage conversion rates of 5 to 8 had been reported on the continent. We therefore adopted a factor of 4 as our Low (leakage) Case, a factor of 5 as our Medium Case and a factor of 6 as our High Case. This gives us a low leakage rate of 13249.9 therms/mile/annum (natural gas basis) as a generic figure for leakage from the 1969 low pressure mains system, a medium figure of 16565.4 th/mi/a, and high leakage estimate of 19874.8 therms/mile/annum. Davenport (1972) estimated that 30 per cent of leakage comes from the medium pressure mains. So the leakage rate from the low pressure system constitutes 70 per cent of the total leakage. To obtain a leakage rate per mile from the medium pressure mains we need to estimate what the 30 per cent leakage rate is and divide it by the number of miles in the medium pressure system. The medium pressure mains only constitute approximately 12.5 per cent of the mains system and the low pressure pipes constitute 80 per cent. Using our mains supply statistics we can see that approximately 61 per cent of the current (1988) system was in place in 1969. Similarly we find that 36 per cent of 1969 services are still in place. These operate at a pressure of approximately 20 mbar. D. The Leakage Distribution Curve By applying our typical leakage distribution curve to our estimated leakage rates we can begin to estimate the ranges of current leakage. Figure 6.1 (page 100) demonstrates leakage distributions for mains and services based on Pickering's factor of four. Having previously established the pipe replacement rate for mains and services, we now have to make assumptions about the effectiveness of the pipe replacement program me in locating pipes with the highest leakages. Clearly the more effective the replacement programme, the lower the resultant leakage rate. For our low case we assume that British Gas has consistently replaced the leakiest pipes since 1969. By assuming this, we make the most favourable assumption in terms of the overall leakage rate. This assumption also implies that none of the replacements have been done on post-1969 pipes, and that the pre-1970 system has not deteriorated further in the intervening 20 years. Our chosen high case is to assume that the pipe replacement is essentially random; that the replacement program me has not been successful in targeting the worst parts of the pre-1970 system. While less favourable sets of assumptions are possible, this appears to us to represent a reasonable high case scenario. Our middle case is taken as the median between the two extremes. E. The Effectiveness of Measures to Reduce Leakage Mechanical and lead-yarn joints will leak unless they are conditioned. Just how many of the joints have been conditioned and the effectiveness of the conditioning is a major key to estimating a realistic leakage rate. The operation and effectiveness of conditioning is a complex question and is dealt with at some length elsewhere (Appendix G). In brief, three main questions need to be resolved: the proportion of leakage due to joint leakage what percentage of the throughput is conditioned the effectiveness of conditioning gas On the question of the proportion of leakage due to joint shrinkage, for the Low Case we assume 45 per cent of leakage is from joints (Marris, 1977); for the Medium Case we assume that 57.5 per cent of leakage is from joints; and for the High Case we assume that 70 per cent of leakage is from joints (Davenport, 1972). On the question of permeation of conditioning into the system we assume for the Low Case that 100 per cent of the medium pressure system is fully permeated with conditioning and that it also reaches 30 per cent of the low pressure system. In the High Case we assume that only 30 per cent of the medium pressure system is conditioned and none of the low pressure system. For the Medium Case we take the average of the two. In neither case does any conditioning affect services. Finally, we assume that conditioning has a maximum of 84 per cent effectiveness at reducing leakage from joints (Crompton, 1985; Arnold 1984). The question remains as to what British Gas does to reduce leakage from breakage, fracture or corrosion. The proportion of leakage from this source is the remainder after allowing for joint leakage. There are a number of ways this source of leakage can be reduced (see Appendix D), but unfortunately data is scarce. Given this lack of information we have settled for what we consider to be a conservative breakage repair efficiency rate of 90 per cent, 85 per cent, and 80 per cent for the low, medium, and high cases respectively. We have assumed a leakage rate of 0 per cent for our low case, 0.25 per cent for our medium case and 0.5 per cent for our high case for the 39 per cent of the mains and 74 per cent of services that have been built since 1969. We expect that the leakage rate from the mains and services built since 1969, which are predominantly plastic, will be lower than the predominantly cast iron pre-1969 system but there is no data available to say how much lower. Thus we have adopted what we consider to be very cautious assumptions. Table 6.1 Leakage Rate from Distribution Mains (Omitted .. unscannable) It should be noted that, in the estimates above, we have not taken the following factors into account: The system that was in place in 1969 is now twenty years older. We have not increased the leakage rate from the 61 per cent of the system despite its increased age and increased strain from such factors as increased and heavier traffic. Clearly this is a conservative assumption, as it is unlikely that the condition of original mains has remained stable over time. We have not increased the average leakage rate to take account of the fact that a marginal increase in supply is likely in general to entail marginal increases in pressure, at least at certain times of the day, and hence to lead to increased leakage. We have not included estimates of leakage from the rest of the supply system (see Page 26). This means that we have not included any leakage from: drilling activities production onshore reception terminals compressor stations pressure reduction systems storage end-use past the meter high pressure pipelines pipeline purging There can be little doubt that leakage does occur from each of these stages. Although we have anecdotal reports of leakage from compressor stations, pressure reduction stations, storage holders and point of production (see relevant appendix) we have no hard data and as such have not included an estimate in our leakage rate-for any of these important sources. F. Conclusion In this analysis, we consider that the true leakage rate for natural gas is likely to fall between the medium and high cases. This is in part because we have not included leakage from the supply system other than the distribution mains but mainly because conditioning of joints seems to be so unsuccessful. As far as can be ascertained from the literature, except for a new system in the North West region known as WISE spraying, described by Clough (1989) as being successful, conditioning has been disappointing in its impact on leakage. II. The Issue of Unaccounted For Gas (UFG) We are confident that a minimum of 1.9 per cent, and probably considerably more, of natural gas produced is leaking from the UK supply system. In this case, why is it not showing up in British Gas or Government statistics? Unaccounted for gas (UFG) is the difference between what is metered as coming into the system and what is metered as going out. In truth it is a composite figure including; Leakage Meter slip (inaccuracy of meters) Meter correction (correction for temperature and pressure) Deviations in assumed calorific value Other small miscellaneous items There is considerable uncertainty when apportioning the UFG figure in to its constituent parts. The most difficult problem from the independent researcher's point of view is that British Gas is the only party with access to information on all of these constituents, and they exercise considerable discretion in presenting statistics. There has been great variation in UFG estimates over the last few years. The UFG figures for 1986-88 were reported to be 845, 537 and 121 million therms (Mtherms) respectively. In percentage of gas metered terms this is 4.5 per cent, 2.7 per cent and 0.6 per cent respectively. This represents a remarkable improvement over such a short period and so far no satisfactory explanation has been offered. It would be helpful if British Gas could fully explain why this figure has dropped so sharply and so quickly. In the recent past, the UFG figure has fluctuated around the 3 per cent mark. The traditional explanation from the industry has been that domestic meters tend to under-read and so the leakage element of the UFG figure is quite low, stated as being 'around 1 per cent'. This implies that domestic meters under--read (due to slip and correction) by quite large amounts (allowing for domestic consumption being half of consumption and also allowing for small contributions from the other constituents of UFG). A. Meter Inaccuracy This traditional explanation of meter under-reading giving rise to high UFG figures and thus leading to overestimates of the leakage no longer seems viable, however. This is because British Gas, with Ofgas and the Department of Energy, have been undertaking major studies of meter inaccuracy since 1988, which have been finding a tendency of domestic meters to over-read rather than under-read. A more detailed explanation of these studies is included in Appendix C. In brief, there have been 2 small studies, which Ofgas consider are not conclusive because of their size (211 and 100 meters respectively), one larger study of 10,000 meters again inconclusive and an even larger study which should be finished soon (one hopes not inconclusive nor confidential). The results of all three finished studies are confidential, but we have, however, managed to glean some information about them. We recognise that meter accuracy is a complex area and that the two original studies were small and therefore not necessarily representative, but given the lack of information in the public domain we have been forced to use what meagre information we have. The two small studies both found that the older Leather Diaphragm Meters (LDMs) and the newer Synthetic Diaphragm Meters (SDMs) both over-read gas usage, about 10 per cent of the LDMs by over 4 per cent. This means that overstating the leakage from the distribution system, domestic meter inaccuracy understates the true leakage rate. We understand that there were sightly under 10 million-LDMs in use in the mid-eighties. If the study data were representative, this could mean that around 1 million LDMs are over-reading by 4 per cent. To obtain a 1988 estimate of domestic meter inaccuracy we assumed a replacement rate of LDMs by SDMs equal to the replacement of service pipes (being the most reasonable assumption to make given lack of information). We also understand that 7 per cent of SDMs over-read in one of the small studies by more than 2 per cent and that the other 93 per cent also over-read on average. We further understand that around 3 times as many LDMs as SDMs over-read by this 2 per cent amount. This implies that around 11.5 per cent of LDMs over-read by 2 to 4 per cent, leaving 79 per cent over-reading by 0 to 2 per cent. On this basis, our assumptions on meter inaccuracy are set out in Table 7.1 below. Table 7.1 Meter Inaccuracy (Omitted .. unscannable) Type of Meters When these inaccuracy figures are subtracted from total UK gas consumption figures (total consumption excluding colliery methane, producers own use, stock changes) we arrive at the adjusted consumption figure and leakage rate as shown in Table 7.2 below: Table 7.2 Leakage Rate Allowing for Domestic Meter Over-Reading (Omitted .. unscannable) On this basis, allowing for domestic meter over-reading adds approximately 0.7 per cent to leakage estimates. It seems unlikely that the drastic cutting of the reported UFG figure could have been achieved through improved control techniques (which are in their infancy in this country) or by pipe replacements (which have not increased significantly), particularly when taking into account the depletion of manual grade staff within British Gas. We find it a curious coincidence that the UFG figure has fallen to 0.6 per cent, which fits well with the British Gas leakage estimate of around 1.0 per cent, at a time when meter under- reading seems unlikely to be a large constituent part of that UFG figure. There appears to be no obvious reason for the recent change, and we do not consider that it adds any great weight to British Gas's 1 percent leakage estimate. There are many ways in which a leakage figure may be underestimated. The principal possibilities are: Producer's own use (a high 7.9 per cent of gas produced in 1988) Difference between actual and declared calorific value of gas metered Inaccurate temperature and pressure correction factors Stock changes It is very difficult to assess the relative importance of these factors given the almost total lack of information available from the natural gas industry. However, one possible area of underestimated leakage is quantifiable in a provisional manner. Total gas available for consumption is the sum of gas produced plus imports, adjusted for stock changes. 'Stock changes' is the net amount of gas that is claimed to be put into or taken out of storage at the year end. One would expect such a figure to balance over time as one cannot keep putting gas into or taking gas out of storage indefinitely. However, the figures for the last four years show precisely this sort of pattern. British Gas has apparently made net additions to storage of approximately a quarter of a billion therms every year between 1985 and 1988. It would be interesting to know what form this storage takes. Storage by 'line packing' (by increasing the pressure in transmission pipes) is both very difficult to measure and to verify. It is theoretically possible that the 'stock changes' figure could be entirely a hidden loss although this would be very hard to verify under present arrangements. We show for the purposes of demonstration what effect this may have on leakage estimates: Table 7.3 Stock Increase as Leakage (Omitted .. unscannable) [] TL: A Study of Leakage from the UK Natural Gas Supply System with Reference to Global Warming (GP) SO: Greenpeace UK DT: 1990 Keywords: atmosphere global warming climate change uk europe gas fuels energy greenpeace groups reports gp / [part 5 of 7] Appendix A. A Basic Description of the UK Natural Gas Supply System A.1 Drilling for Natural Gas The only method of proving whether hydrocarbons are present in a given location is to drill to the appropriate reservoir structure. Drilling on land is relatively straightforward, but under sea it becomes more complex because of-the need for a firm base. There are three main drilling rigs used at sea: Jack-up platforms are usually used in seas up to 100 metres deep A semi-submersible rig is used in seas of around 100-250 metres. A drillship is used in deeper waters. This looks like an ordinary vessel but is designed to have a drill running through the bottom of the vessel. In rotary drilling, penetration of the sea bed rock is achieved through rotating a column of drilling pipe under its own weight. Power is provided by a rotary cable on the derrick floor which drives a section of pipe about 12 metres long (the kelly) downwards. As the kelly moves down it is replaced by an extension piece. The penetration is carved out using a drill bit. Between the bit and the kelly is a pipe string, which is about 9 metres long and has an outside diameter of about 10 centimetres. Around the drill is pumped drilling fluid, known as mud. This passes down the kelly and the pipe string and through the bit. It then returns to the surface in the gap between the drill and the walls. Methane bubbles up through the mud and escapes to the atmosphere. However, the amount released in this way has not been quantified. When drilling is complete, the well is cased by a pipe set in cement. The lower portions of casings are not usually inserted unless tests indicate a reasonable probability of flowing oil and gas. If it seems likely that a suitable formation has been encountered the casing is completed and perforated. Production tubing is run to just above the perforation. The mud is replaced by lighter fluids and the well is allowed to flow. The quantity of gas available in the well can be estimated by allowing a well to flow at a certain rate for a given time and then measuring the change in the equilibrium pressure at the perforation point. According to the 1989 Brown Book, there were 93 exploration wells and 84 appraisal wells drilled, a total of 177. The total number of exploration and appraisal wells in the United Kingdom Continental Shelf (UKCS) is now over 2000. Of these, 1500 exploration prospects have been penetrated, of which there are 271 significant discoveries. This represents a success rate of 1 in 5.5. The ration of exploration we discoveries which are considered commercially viable is about 1 in 12. From this we can see that several of the wells that were penetrated and found to be a significant discovery are not considered commercially viable (about 1 in 12). It is worth noting that drilled but unused, capped only wells are considered to be a major leaker of methane if the wells are onshore (Peter Proudlock, pers comm). The extent of the problem underwater is unknown. A.2 Production of Natural Gas When a gas field has been discovered, drilled and positively evaluated, a decision has to be made whether to develop it. The main factor that is considered is whether or not it is economic, that is whether the cost of development will be recouped from the gas produced and transported to be sold. As discussed in the previous section, the economically viable wells are far smaller in number than those deemed to be significant discoveries. Each well is capped with a 'Christmas tree' of valves. The most important are: the storm choke at the base of the well which will close if a pre-determined flow rate is exceeded a valve on the Christmas tree itself which is designed to close if the pressure of the gas goes above or below certain levels Venting is a major source of escaped methane to the atmosphere during production. We have not been able to find reliable estimates of venting. Not only is it difficult to calculate venting from oil fields, which sell the associated gas produced as a by-product of oil production to the supply system, and venting of gas from gas fields, but it an even more vexed problem to decide whether gas vented from oil production counts as methane leakage from the UK natural gas supply system. This study considers natural gas leakage from oil fields to be relevant to the oil industry and has not included it within estimates of leakage from the natural gas supply system. The Brown Book gives no information on venting from gas fields but it does give the following information on gas flared at offshore producing oil fields. Table A.1 UK Gas Flaring (Omitted .. unscannable) It is estimated that 20 per cent of the reported vented and flared gas from United States gas fields is vented (Lashof and Tirpak, 1989). Abrahamson (1989) using this estimate, calculates 0.13 per cent of natural gas is vented from natural gas fields in the United States. In addition, he makes the assumption that venting from oil fields is similar to that from gas fields. Anecdotally, it is estimated that the equivalent of 5 per cent of flared natural gas is vented in the UK. Wallis (1990) estimates a 1 to 5 per cent leakage rate during production, however he cites no supporting evidence and we have not been able to find any. Offshore production rigs are very complex and it is likely that there is routine escape of methane. Methane is flammable between 5.3 to 15 per cent volume in air and production engineers will be anxious to keep leaks down below this level. The Piper Alpha Enquiry may supply more information on leakage from production platforms when they report later in the year. A.3 Natural Gas Terminals In the UK the shore or 'beach' terminals are operated jointly by the producers and the transmission companies, currently, British Gas, Quadrant and BP Gas Marketing. Throughout this study we will refer to British Gas as the company which transports the gas to the consumers, although this is not always strictly true. It is the producers who are responsible for the delivery of gas to specification. British Gas receives the gas at the terminal, adds the odourant, carries out tests to check the specifications and sends the gas into the transmission system. A.4 Gas Pumping Machinery or Compressors Compressors compress the large volumes of gas down to a manageable volume. The resultant pressure then pushes the gas throughout the system. There are 15 compressors throughout the UK, including the plant at St Fergus. In the United States, there are 2 major types of compressor engines: the reciprocating engine and gas turbine. Losses of methane from reciprocating engines can be significant with EPA (1985) indicating that 4.34 per cent of the methane used as fuel is released to the atmosphere. A.5 Pressure Reduction Stations In order to be able to transport large volumes of gas, it is necessary to transport gas at high pressure, for example around 1000 psi in the high pressure network. This pressure must be progressively reduced to around one half to 1 psi before end use. There are around 100 offtakes from the high pressure system and 1750 pressure reduction stations throughout the UK (Spearman, 1987) for this purpose. Governors are used to achieve this pressure reduction. Heaters may be installed at some governors in order to counteract the consequent fall in temperature pressure is reduced. The fall in temperature of the gas can give rise to the following problems: methane hydrate formation may occur if there is any moisture in the gas, and the pipe may become blocked damage may be caused to mains either by temperature stress or because of freezing in ground moisture. In general, the rule is that for every 50øF rise in temperature required the heat requirement is 1 Btu for each standard cubic foot of gas passing. A pressure drop of 100 lbf/in2 will reduce the temperature by 7ø. A pressure reduction station or governor station is made up of the following main sections: The Bridle Gas Cleaning Equipment Gas Heater Control Governor Each of these sections could be areas for leakage. Although we have no evidence of leakage from pressure reduction stations, they are reported to have high leakage rates of around 5 to 7 m3/hr. A.6 Storage The possibility of storage gives natural gas a degree of flexibility not available to the electricity supply industry. A.6.1 Seasonal Storage Aquifers and depleted gas fields such as the Rough field and particular fields like the Morecombe field which is used exclusively to supply seasonal demand, are the methods used to provide storage of sufficient capacity to meet winter demand. Depleted gas fields have the following advantages over aquifers: gas fields are known to be tight the physical properties of the field are known from years development costs of an aquifer tend to be high Not all depleted fields or aquifers are suitable for storage, however. To be of use as a store, the field must have high permeability to allow for fast rates of flow during peak demand and to allow for a steady flow in the opposite direction for filling. A.6.2 Peak Shaving Peak shaving stores are storage facilities which generally operate for only a few weeks each year. The storage takes a relatively long time to fill but can produce large export volumes over short periods of time. The two main methods are the use of liquified natural gas and salt cavity storage. A.6.3 Liquified Natural Gas The storage of gas in cryogenic tanks to -160øC is well established and has the advantage of reducing the volume of gas to around one six hundredth of the volume at standard temperature and pressure (stp). In the UK, LNG is used mainly for peak shaving, although in other parts of the world it is used for diurnal storage as well. The liquefaction process requires the following plant: liquefaction installation storage vessels pumps to draw LNG from storage and deliver it at grid pressure vapourisers to vapourize LNG to gas odourisation facilities A.6.4 Salt Cavity Storage A salt cavity is formed by leaching a rock salt stratum with brine until a cavity of the required size has been formed. Six cavities, each with a releasable volume of 30 X 106m3 were reported to be under development at Hornsea in the UK (Dean 1985). A.6.5 Diurnal Storage Diurnal storage is the type of storage required on a daily basis, to cope with short-term variation in demand. A.6.6 Low Pressure Storage The main type of low pressure storage is low-pressure holders. These are usually positioned on the sites of former gas manufacturing plants. They originally exerted a pressure on the local distribution system by virtue of their own weight. Distribution pressures are now higher than this exerted pressure from weight, and so these sites now use boosting equipment. It has been impossible to quantify the numbers of gas holders or the leakage problems associated with them. However, Brooks and White (1987) discuss the 98 gas holders in the North Thames district. Their statistical data is reviewed in the table below. Table A.2 Age of Gasholders (Omitted .. unscannable) On the integrity of these gas holders, Brooks and White comment: "the age,of the low pressure holders is such that it is now prudent to consider replacement storage should it be necessary to decommission some of the holders during the 1990s" In addition, Pickering et al (1970) report holder losses as being 0.5 per cent of the town gas throughput of the system. A.6.7 High Pressure Storage The advantage of high pressure storage is that large quantities of gas can be stored under pressure in a much smaller volume because gases is compressible. The following are the main methods used: A.6.8 High-pressure holders These are a high pressure version of the low pressure storage holders with the added advantage of a much smaller volume and less unsightly holders. Generally the holder is a bullet shaped steel vessel about 3.6m in diameter and 70-100m long. A typical installation may contain 10 or 12 of these vessels linked together by a manifold. Unless NG is available directly from the transmission lines the holders are usually filled using reciprocating compressors. These holders were originally intended to operate at 70 bar maximum but often run at half this pressure. A.6.9 Pipe arrays The concept is the same as high pressure holders except that the pipes are laid in parallel and buried. Longer lengths and therefore larger volumes can be stored. This method requires a large vacant site, however, which is not always available in the urban environment. A.6.10 Line Pack Line pack storage is the practice of storing natural gas in the transmission lines. It is the most utilised form of storage. Thompson (1988) states that it meets 53 per cent of the diurnal storage requirements of the region. The natural gas transmission system is based on maximum source pressure and minimum terminal pressure. Under these conditions the system is fully utilized and will sustain the maximum flow. If the flow in the system is reduced but maximum source pressure is maintained then pressure at the terminals will increase and the system will contain gas additional to demand. This additional gas then constitutes line packing. The quantity of line pack available is determined by demand and by the number of compressors in use. Compressor running costs are high and running additional compressors to provide an increase in line pack is only economic when the total cost of line pack is less than that of other alternative forms of storage. Gas is released from line pack either by restricting source supplies and so reducing the pressure over the system, or gas is released as demand changes, thereby reducing pressure at the terminal of the system. Line pack storage has the following advantages: By controlling the input sources to the system, the line pack system is self-operating It is a linear system and operates throughout its length, so line-pack storage is available at any point on the system It is transferrable storage There is potential for very large storage volumes The system is buried and therefore aesthetically acceptable. Line pack has the following drawbacks, however: On days that storage is fully utilized, the extremity of the system is at minimum pressure when demand is near its peak. If the pipeline is out of service both the transmission capacity and storage capacity is lost at the same time. A.7 Past-the-Meter and End-use We have no estimates of leakage which occurs from the pipes which transport gas around the consumers premises after the meter. Some indication is given by the 'essential service' jobs undertaken by British Gas; 8.38 million such jobs took place in 1988. British Gas does not report whether all these essential service jobs are related to leakages. In addition, we have not included leakage from end-use appliances. In 1988, British Gas had 17.08 million customers. Each of these customers have gas outlet points some of which have automatic ignition and pilot lights. However, a proportion of these outlets require manual lighting. For these latter outlets, methane is released for around 0.5 to 1 seconds (our estimate) before it is lit. We are unaware of any studies which have estimated this release. Appendix B Problems of Metering B.1 Introduction The following section on metering is based on Conner (1987). Readers should turn to that paper for a fuller understanding of the complexities of metering. When natural gas enters the distribution system from the rigs it is metered in by the company selling the gas, either on the rig or at the beach, by British Gas and by the Department of Energy (DEn). In addition, British Gas will again meter the gas after it has been blended. Each region of British Gas meters the gas as it moves from the national transmission system into the regional transmission system. At the beach is the industry term for the point at which natural gas moves from ownership by the producing company to British Gas. The DEn measures the gas as a means of extracting the producing companies. This is one area where, if the information is released, a check can be made between production estimates from British Gas and the producing company. Large volumes of gas at high pressure have caused problems for metering. The only practical, acceptable meter is the orifice plate, which is widely used in the transmission system. Orifice plates must be accurately made and installed if a reasonable degree of accuracy is to be hoped for (British Standard (BS) 1042). Natural gas is metered as it reaches the reception terminal. Corrected to a standard temperature and pressure (30 inches mercury and 600F (15øC, 1013.2 mb) Bowler (1987)). A major problem for British Gas is to measure natural gas coming in to the transmission system and natural gas leaving the system at this same standard temperature and pressure. Because the quantity of energy supplied varies with temperature and pressure conditions, it is the practice to correct gas volumes to the stated standard temperature and pressure conditions. It is important when making the correction to ascertain the moisture content. Natural gas may become saturated with water through contact in gas holders or mains. In addition when carrying out corrections, the compressibility factors must be known. Corrections are therefore very complex calculations. It is possible to equip meters with automatic correction devices but the Controller of Gas Standards has not as yet approved such devices because of the difficulty in checking them when in service. Given these complexities, it is clear just how difficult it is for British Gas to accurately measure the volume of natural gas passing through the system. It is not possible to say with certainty the volume of gas that passes into the system, nor therefore to determine the volume of leakage. B.2 Meter Standards A basic requirement of meters is that they are within the legal requirements of safety and accuracy. In the UK, these requirements are set out in the Gas Safety (Installation and Use) Regulations 1984, Gas Act 1972 and Gas (Meter) Regulations 1974. Meters which are used as a basis for charging must be stamped or 'badged' except if a customer has a special contract. All badged meters must be accurate to within plus or minus (+-) 2 per cent. It is assumed that the meters work in the interests of the consumer, yet from meter accuracy tests this does not appear to be borne out in practice (see Appendix C). B.3 Meter Accuracy and Temperature The volume of natural gas depends on its pressure and temperature. Temperature is more difficult to control than pressure since temperature can be affected by circumstances external to the pipeline, for example the proximity of a warm sewage pipeline. The expansion of any gas from a high pressure to a lower pressure results in a drop in the gas temperature. This is known as the Joule-Thomson effect. It produces a loss in temperature of about 0.60C for every one bar reduction in pressure. This is a temperature loss of about 36øC when pressure drops from 70 bar down to 10 bar. When translated into volume, Charles' Law states that for every one centigrade change in temperature there will be roughly a one third per cent change in volume. Therefore if the temperature increases the volume of the gas increases and if the temperature falls the volume of the gas will fall. Thus a 3øC change in temperature will change the volume by 1 per cent. It would be preferable if the temperature of the gas remained at its standard measuring temperature: around 15øC. But in practice the loss of temperature when moving from different pressures, ambient temperature, temperature of the ground, and temperature loss in normal running requires a very finely honed system. Thus it is not inconceivable that a 1øC mistake in temperature can allow the registered volume passed through a pressure reduction station to be out by one third of a per cent. As an illustration of the difficulties, the average measured temperature difference between the Scottish and South West regions is on average 2ø to 3ø throughout the year. B.4 Meter Accuracy and Moisture Natural Gas must also be kept below a certain maximum moisture content to minimise the risks of condensation. Water forming in pipelines will run to a low point and may cause a blockage of the natural gas and possibly result in an explosion. B.5 Types of Metering The type of consumer dictates the type of metering undertaken by British Gas. There are two main classes of meters: quantity or positive displacement types rate-of-flow or inferential types Quantity or displacement types can be further sub-divided into: diaphragm wet rotary displacement Rate-of-Flow types are more numerous and include: turbine anemometer pressure differential variable area time of flight laser doppler ultrasonic vortex shedding swirl The most widely used meters are: B.5.1 Diaphragm Four chambers in the meter fill and empty in turn. Sliding valves control the entrance and exit to the compartments. The exact volume of the compartments is known, so by counting the number of movements by the sliding valves the volume is measured (see main discussion of leakages for explanation of the accuracy problems of this type of meter). B.5.2 Rotary Displacement Meters (RDM) The RDM has been extensively used for low pressure measurement, reportedly with performance accuracies of +- 1 per cent (Connor, 1987). If not correctly installed the RD may give rise to the following common problems however: Jamming can occur if dust or debris is trapped between the impellers and the case gradually causing the meter to stop and the gas flow to be restricted. Pulsations may occur with a changing load and the impellers may be unable to smooth out the pressure. This may effect local control equipment such as governors and pilot supplies. B.5.3 Turbine Meters Large consumers who demand fast flow natural gas, for example to steel works, are likely to have a turbine meter. Turbine meter accuracy is given as +-1 per cent and is dependent upon achievement of an established velocity at the meter inlet. Meter inaccuracy may be caused by: blade damage flow pulsations which cause the meter to read high swirl which produces an error dependent on the swirl angle B.5.4 Orifice Plate Meters The majority of natural gas bought and the largest gas sales are made using these meters. Accuracies of the meter are dependent on the installation and conditions of flow but accuracies with 0.6 to 0.75 per cent can be achieved. However, the performance can be influenced by: Erosion which can produce changes in edge sharpness. Pipe wall roughness may give errors of up to 5 per cent (Connor, 1987). swirl or pulsating flow created by governors, compressors and bends may result in an error of up to 15 per cent at a swirl angle of 40ø (Connor, 1987). dust before the orifice plate can also reduce accuracy. A filter, flow straightener and regular checking can reduce these errors. B.6 Secondary Instrumentation Only the orifice meter requires secondary instrumentation to derive a flow reading. However, to reduce the measured volume back to the equivalent base volume, secondary instrumentation is used with all meters. The types of secondary instrumentation are: Differential pressure or pressure transmitters which have a nominal accuracy of around +- 0.5 per cent temperature transmitters density meters - accuracies vary between +- 0.2 absolute and +- 0.5 full scale deflection Automatic pressure/temperature correctors are available in two basic types: mechanical and electronic with accuracies quoted as +- 1 per cent absolute and +- 0.25 per cent full scale deflection. Automatic pressure/temperature/compressibility correctors: the trapped sample and the density cell. The former has a given accuracy of +- 1 per cent and the latter +- 0.2 per cent full scale deflection. A summary of these official meter accuracies is given in the table below. These are accuracies undertaken in optimal conditions. Anecdotally, meters are said to be most inaccurate when they are measuring large volumes of gas. However, we have not been able to find any evidence of the rate of inaccuracy. An american paper (McConaghy et al, 1989) states 'that build up of solids and liquids on the plate surface and increases in surface roughness result in big changes in flow rate'. They do not say what these big changes are and whether they result in under or over read, however. Table B.1 Meter Accuracy (Omitted .. unscannable) Appendix C Domestic Meters The diaphragm meter (DM) is used in domestic and small commercial and industrial consumer units. A diaphragm is a measuring mechanism which moves across a container and as it moves across it measures the gas. Most domestic installations have a governor before each meter which is meant to check the pressure and temperature. Originally the meter diaphragms were made of leather. However, over a period of time and use many of these diaphragms have gradually stretched and become inaccurate. Ten to fifteen years ago British Gas decided to move to synthetic diaphragm meters (SDMs). As described in Section 5. a study of meter accuracy was undertaken in 1988 by the Gas Consumers Council (GCC) of 211 synthetic meters. Their results showed that 7 per cent were over the legally acceptable margin of error of +- 2 per cent of real gas use. These 7 per cent were over-reading between 2.2 and 3 per cent with one reading around 5 per cent over. Clearly the bias of the sample was towards over-reading. This study made clear that SDMs were substantially more accurate than LDMs which are the domestic meters still most commonly in use. The Gas Consumers Council then passed on this study for expansion to Ofgas. The GCC study and the studies in progress are reported in the Ofgas 1989 Annual Report, but no results are given. Ofgas, the Department of Energy (DoEn) and GCC all take the view, and are bound by law in the case of Ofgas, that the information is confidential and it is up to British Gas to release it as they see fit. However, a reply to a Parliamentary Question to the Secretary of State for Energy concerning the Ofgas study, indicated that 'the study referred to was commissioned by the Office of Gas Supply. It is therefore a matter for them'. This clearly indicates some confusion, but unfortunately remains unobtainable at the present time. This sample study by Ofgas supported the GCC suggestion that LDMs are 'very much more' inaccurate than SDMs. This study was then enlarged to 10,000 SDMs. The results of this larger study were deemed inconclusive and confidential. A further, larger study should now be completed (March 1990); This is again a cooperative venture between the Department of Energy and British Gas. We understand that in the study of 100 meters the preliminary results of the Gas Consumers Council were upheld, but DEn were not able to give out any information. Meter accuracy is obviously very important when trying to track down leakage. If there is a bias in the system, as the GCC initial study showed, then British Gas is reporting that more natural gas has come out of the system (ie been sold) than really has. This would mean that the unaccounted for gas figure which includes leakage could be underestimated, and, in turn gas leakage may be underestimated. Appendix D Pipelines The gas transmission and distribution system is a combination of old and new pipelines which transport gas at different pressures. D.1 History of the transmission and distribution system Gas has been distributed to customers by pipeline in the UK for 150 years. Originally the supply systems were limited by available materials and the pressure available from the point of manufacture. Usually the gas-making plant was at the centre of the supply area. These factors resulted in the development of a tree system of supply with large diameter mains radiating from the point of production to the farthest customers, with branch mains spreading out from these trunk mains (Bowler 1987). Until 1949, gas was manufactured and supplied by hundreds of independent companies. In 1949 it was decided to nationalise these companies and 12 area boards were established. Vesting Day, 1 May 1949, was for a distribution system which was a disjointed and overloaded mass of low and medium pressure mains, often badly war-damaged. From that time, the regional boards set in motion programmes for the rapid expansion of gas use. This was to be in tandem with post-war reconstruction. The major obstacle to fulfilling the boards aims in this post-war period was a lack of materials, however, which may well have compromised the quality of the pipe work. In 1972, the regional boards were amalgamated to form British Gas. This was in large part to coordinate the changeover from town gas to natural gas which had begun in 1963 (Brown, 1984). Natural Gas was to be transmitted from the North Sea by high pressure (up to 1000 psi) national transmission lines, made of steel and between 24 and 42 inches in diameter. The laying of these pipelines has made up a large part of British Gas's new mains laying programme. D.2 Materials Since the mid 19th century, most low and medium pressure pipelines were made of grey cast iron because of its good resistance to corrosion and because the material was readily available. However, its high carbon content which makes it corrosion resistant also makes it a brittle material. It is therefore susceptible to fracture, particularly from heavy traffic or ground heave either from frost or drought. In addition, cast iron can become weakened by fissure corrosion. This can happen as a result of stress which induces corrosion of the iron at grain boundaries, producing fissures. If this continues over a number of years the iron disintegrates into carbon flakes. This is known as graphitisation and a fully graphitised pipeline retains the appearance of a new pipeline but has little strength. During the early 1920s the centrifugal casting process (spun iron) came into operation (King, 1977). Spun iron therefore gradually replaced cast iron. In the late 1960s cast or spun iron was superseded by ductile iron. This has greatly improved impact resistance and resistance to general and fissure corrosion compared with cast iron. These properties are produced by adding magnesium to molten iron during production. Although it is a far superior material to cast iron it still requires mechanical 'stanlock' joints which bring their own problems. Ductile iron is mainly used for medium pressure mains. Modern low pressure mains mainly use polyethylene and 90 per cent of low and medium pressure distribution pipes currently being laid is in this material. It is extremely ductile and can be joined by a number of fusion techniques which exclude the need for mechanical joints. Polyethylene does not degrade or corrode although constituents of some manufactured gases can have a detrimental effect on the material. Because of its ductility polyethylene pipes can be inserted into old cast iron pipes for pipe renewal. Smaller diameter polyethylene pipes can be laid from a roll thereby reducing the number of the joints required. As noted earlier, the high pressure transmission lines are made from steel. The older lines, first laid in 1963, were 24 to 36 inch diameter but increasingly new mains are up to 42 inch to give greater flexibility for storage by line packing. Steel is also widely used for services. The high pressure lines have a protective coating against corrosion (not always very successful (Corcoran and Argent, 1985) but only 40 per cent of services have a similar protection. D.3 Pipeline Pressure In the UK the maximum recommended pressure is 75 bar. The transmission and distribution system operates pipelines at the following pressures: Table D.1 UK Pipeline Pressures (Omitted .. unscannable) The domestic distribution network is made up of low and medium pressure pipelines. The low pressure mains operate at around 30 mbar and the service pipes at around 20 mbar. Generally the operating pressure is kept to a minimum which is consistent with a safe supply and which, at the same time, ensures minimum leakage from the older parts of the system. Appendix E Service Pipes Service pipes are the pipes that take the gas from the low pressure distribution system to the meter of the customer. After the meter the pipes in the house of the customer are the customer's own responsibility. But British Gas is responsible for service pipes. British Gas does not report the total number of service pipes in use nor does it report the total number of miles or kilo metres of service pipes there are. British Gas simply reports new services and services relaid. An alternative method of estimating length of service pipeline is through number of customers, however. Prior to 1972 and the creation of British Gas, some of the regional boards reported number of services laid or relaid. Even amongst those regions that did report services there is no annual continuity of reporting with odd years omitted and so on. There are a few odd references to services in the King Report and Marris. Marris (1977) reports that 'services are a major part of the distribution system....the total length of services in the North Western Region is almost equal to the length of mains'. Table E.1 Services in the North West Region, 1976 (Omitted .. unscannable) Of these 2 million services 90 per cent had been laid since 1953, showing that the average age of services is much less than that of mains. Marris stated that 95 per cent of all service leakage is a result of corrosion of the pipe wall. The steel tube which was wrapped with coal tar and fibreglass and which was installed without insulation from the cast iron mains is particularly susceptible to anodic corrosion through the wrapping. He considers the only economic way of repairing services is to replace them. The King Report states that like mains, it would be too expensive to replace all service pipes, and that a renewal rate of 2.5 per cent per annum appears 'reasonable'. Clough (1989) although he gives no estimate of leakage from services does show the ratio of service to mains reports (see Figure E.l, page 101). This shows that there are more calls about services than mains and would support Marris's assertion that: "escapes occur almost as frequently as escapes from mains." Appendix F Reasons for leakage from pipelines and means of detection and repair [] TL: A Study of Leakage from the UK Natural Gas Supply System with Reference to Global Warming (GP) SO: Greenpeace UK DT: 1990 Keywords: atmosphere global warming climate change uk europe gas fuels energy greenpeace groups reports gp / [part 6 of 7] F.1 At Risk Pipelines King (1977) outlined certain factors by which mains could be judged as being at risk. steel mains without corrosion protection small diameter grey cast iron mains (particularly when operating at medium pressure or where such mains are close to premises with cellars or basements) mains which have a history of fractures mains which have a high incidence of joint leakage which does not respond to gas conditioning mains where pipe material condition is suspect mains which are in areas of local subsidence mains which are in areas of corrosive soils Marris (1977) has also explained the problems in estimating leakages from pipeline. He uses a demerit system by which mains were given demerit points depending on their location and other factors. Marris's factors are very similar to King's and Proudman (1988) provides an illustration of the main factors (Figure 5.3, page 99). This section serves to illustrate the many variables which may affect actual leakage rates, and may render any estimate of leakage uncertain. Better information in the public domain is needed. F.2 Types of Leakage from Distribution Mains and Services There are 3 main ways for a pipe to leak: from fractures from corrosion from pipe joints In the sections which follow, these three are considered in greater detail. F.2.1 Fractured pipes Fractures are produced by either natural causes or interference from third parties. The main factors influencing fracture are: Small pipes are more likely to fracture than large diameter pipes because of beam strength. Pipe material. For example cast iron is more brittle than ductile iron Soil conditions. The behaviour of clay is particularly dependent upon moisture content. Frost heave in the severe winter of 1962-3 and the drought of 1976 produced a dramatic increase in the number of mains fractures. This past year's drought must also have increased the likelihood of pipe fractures. Cast Iron deteriorates with age and becomes-more susceptible to fracture as explained in Appendix Traffic loading is a very significant factor which is increasing with the greater volume and axle weights of road transport. Graphitisation as explained in Appendix D. Corrosion causes pitting or a 'pepper-pot' effect on iron pipes. As a result the gas leakage is distributed over the entire length of corroded pipe, making it difficult to trace and repair. Steel pipes are likely to corrode, particularly at areas which are uncoated. Corcoran and Argent (1985) describes the problems involved in maintaining a 100 per cent coated high pressure transmission system. It has been reported that corrosion accounts for up to 95 per cent of all leaks on services (Marris, 1977). The connection between 2 dissimilar metals, such as cast iron and steel, causes anodic corrosion currents in the service pipes and loss of metal at the uncoated areas. F.2.3 Leakage from Pipe Joints There are many types of pipe joints (see Figures F.l, F.2 and F.3, see pages 102-104). The traditional method of jointing cast iron joints was to pack the joint with jute or hemp yarn and then cover the joint with lead. This type of joint has been superseded by mechanical joints in which the rubber ring is inserted into the annulus and compressed into place. These mechanical joints are still in use for medium pressure ductile iron pipes. F.3 The Reasons for Breakage, Fracturing and Corrosion of Pipelines and Joints There are 3 major contributors to breakage, fracture or corrosion of pipelines and joints: environmental effects (primarily climate and effect on subsoil); human external effects (mining excavation or subsidence, increased traffic load); engineering (inadequate pipe laying, quality control of material or workmanship, physical characteristics of material) (King, 1977; Marris, 1977 and Proudman, 1987, see Figure 5.3, page 99). These broad areas are discussed further below. The beam strength of a main is proportional to its diameter and wall thickness. Therefore a 2 inch diameter cast iron main is more susceptible to fracture than a 24 inch diameter main. Analysis in the North West region has confirmed this (Marris, 1977). The material of the pipeline or joint is important. Grey cast iron mains are prone to fracture because they require small amounts of stress to break. In addition much of the grey cast iron piping was pit cast without quality controls. However, the corrosion properties of cast iron are very good, so in some situations they are preferable. Sub-soils have differing corrosive qualities, in declining order: cinder, clay, loam and rock and sand. Climatic factors, according to King (1977) are the most important. Ground movement as a result of frost heave or drought will cause pipes to break. The 1962/3 winter and hot 1976 summer clearly showed increased break ages. The age of mains is not in itself a significant cause of break ages or 'fractures result not so much from age or corrosion as ground movement' (King, 1977). While the old pre quality control cast iron pipes are open to fracture there is now evidence that the newer, quality controlled, spun cast iron pipes are as susceptible to the old cast iron. The increased number of vehicles on the road, and increased loads of that traffic are significant. The Transport and Road Research Laboratory has shown that road damage is proportional to the fourth power of axle weight. Disturbances of the pipeline environment can cause break ages. For example, broken water mains can cause hollows to develop leaving pipelines suspended in air. Inadequate backfilling can allow the ground to resettle, again causing a loss of support for the pipeline. Human interference from mining or excavation can also cause breakages. F.4 Leakage Detection Systematic detection surveys are undertaken but the majority of leakages repaired are as a result of those notified by the public (PRE's). An efficient means of receiving and acting upon reported leaks is vital; but inevitably this can combat only the more acute leakages. A pipeline or joint may leak but be below a detectable level, usually thought to be 2 ft3/hr (Clough, 1989). Leakage surveys are carried out using the flame ionization method (FIM). In this instance the equipment is contained in a vehicle which patrols the streets. This method has a serious disadvantage in that the readings are unable to quantify the leak because the vehicle may make its readings at the edges of a methane cloud or at its centre. Infra-red gas detectors are increasingly being introduced. These are smaller than the flame ionization equipment and able to differentiate between different gases. Beams of infra-red light are uniquely modified by different gases. The detectors are able to analyse how the infra-red beam is modified and thus what gases are present. Detection of methane does not indicate the source of the leak, however. Because low and medium pressure pipelines are often laid in tunnels containing telephone wires, water pipes or sewage pipes, a leak from a gas pipe may have travelled some way along a tunnel before it is detected. Tracking down that source can be a tortuous process. The method used for locating pipeline leakage is known as the bar hole method. In this procedure, a metal rod is put into the ground and an air sample is taken. This method is far from satisfactory (Bowler, 1987). British Gas is developing a new system which detects noise from leakage. The system operates with a series of microphones in a vehicle which detect noise in a pipe. The noise is greater at points of gas release. This should allow the detection of the exact spot and therefore the amount of guesswork excavation should be reduced. However, we have not been able to discover whether this method is widely used by British Gas. F.5 Leakage Repair A leak once found must be repaired. There are 4 basic means of repair. In ascending order of cost they are: F.5.1 Network Analysis The optimisation of system pressures is the most important means of leakage control. Since leakage is a function of pressure it is necessary to maintain the minimum pressure required to maintain supply and flow and a minimum leakage rate. One means to do this is to keep the different pressure systems separate from each other. This is the case in the UK where the high pressure systems are separate from the low pressure distribution network. However, it then becomes increasingly complicated to balance pressures in a system to meet peak demand and to limit leaks from a leaky system. This is done by various network analysis techniques which employ differing means to reach the same end. One such method of network analysis is to have control facilities at district governor outlets. Governors control the pressure at the supply points from the medium to low pressure distribution networks and are set to provide a safe minimum pressure at the edges of the system during periods of high demand. Because demand is for short periods of time the system is at that time operating at a higher pressure and therefore leaking more than is necessary. The network analysis control will develop a means of reducing pressure at times of minimal use, so lowering leakage and then increasing pressure, and leakage, to meet demand. F.5.2 Gas Conditioning This is the term used to describe the injection of chemicals into the gas which are designed to reverse the effect of natural gas on pipe joints and then to maintain the improvement through continuing use of gas conditioning. Gas conditioning of rubber joint rings was introduced around 1970 and has been reported as being successful for mechanical joints (Clough, 1989). However, Robinson (1986) reports otherwise (see section F.4.3). Lead-yarn joints have remained a problem, however. Humidification with water was used but was only-successful as a holding operation. Diethylene glycol (DEG) was then used and provided a better percentage recovery but was not altogether successful in preventing leakage. Recently monoethylene glycol (MEG) has begun to be used in WISE spraying (Clough 1989) and can produce almost complete recovery by swelling the yarn. MEG can be used either as a fog which is evaporated by the heat of the gas or as a vapour produced by spraying onto a hot plate. At present British Gas does not publish information concerning what percentage of pipes have been treated with MEG or other hods. It would be helpful if this policy could be reversed in order to allow a more accurate assessment of the condition and leakage rates of joints. See section 5.5 and 5.6 and Appendix G for discussion of conditioning techniques and their efficiencies. F.5.3 Joint Repairs Many methods of repair have been developed for joints. These include internal sealant injection from a pig moved through the pipeline; the filling and draining of a pipeline with sealant and the installation of clamps. The latter is really only possible with large diameter pipelines, but has a serious disadvantage in that it necessitates a disruption of supplies. Leakage from broken joints can be very serious and necessitate major repair operations (Robinson, 1986). Robinson describes how the East Midlands 'major headache'; 6.2 kilo metres of 24 inch diameter main was repaired over a 12 month period at the cost of three quarters of a million pounds. He describes how, prior to the program me of fitting weco-seal inside 1230 joints, there had been 135 joints rebolted or encapsulated between 1971 to 1982. In addition, a flame ioniser method (FIM) survey in 1983 gave a further 26 indications of leakage. The pipeline was made of spun iron with staveley spigot and socket flexible joints (Figure F.2, page 103) sealed with square rubber rings held in position by a back plate fastened with hook type bolts. F.5.4 Mains Renewal The traditional means of mains renewal is laying a new main, joining it to the old system and disconnecting the old part of the main. This procedure is very expensive, disrupts supply and is used generally when pipes are badly corroded. Insertion of polyethylene into low and medium pressure main is now possible. About 90 to 95 per cent of renewals of mains use polyethylene. This technique is also extensively used for service renewal. F.6 Mains Replacement Policy and Effectiveness Replacement of mains will occur naturally over the course of time due to the following factors (King, 1977; Marris, 1977): main or service being in very poor condition main being undersized properties supplied from the are to be modernised major road construction or relevelling changed traffic conditions subsidence due to water movements or mining activities In addition, British Gas implemented a policy aimed at replacing mains which were considered the most hazardous or at greatest risk of taking and then causing an explosion (King, 1977). King states that mains at the greatest risk are steel mains without corrosion protection; small diameter grey cast iron pipes (particularly when operating at medium pressure), or where such mains are close to premises with cellars and basements); mains which have a history of fractures, a high incidence of leakage which does not respond to conditioning or where the pipe material is suspect; and mains which are in areas of local subsidence or in corrosive soils. It should be noted that the King Report was investigating serious explosions and his recommendations were aimed at reducing explosions. As a result, he is likely to consider a heavily leaking pipeline in the countryside as less of a hazard than a pipeline with a smaller leak in an urban environment. Marris set out a method for deciding priorities of replacing mains. He assigned demerit points to characteristics of pipelines so that it would be possible, having total led the demerit points, to rank the mains so that the most hazardous mains are renewed first. Table F.l Pipeline Replacement and Demerit Points (Omitted .. unscannable) We do not know whether British Gas has a planned replacement programme based on the above recommendations. However, King reports that 'at least one region of British Gas expects to have all small diameter cast iron pipes in the more hazardous locations replaced by 1984'. This represented about 8 per cent of the total low pressure mains of that region. King also recommended that British Gas relace all higher risk priority mains by 1984 at the latest. We understand that a follow-up report, known as 'King 2', investigated whether or not this recommendation had been carried out. We have been unable to obtain a copy. An alternative means of categorising hazardous pipes is referred to by Marris, 1977, and Proudman, 1987. They refer to location categories (A, B and C) agreed by the Distribution Engineers Committee. These categories, A, B and C, are based on such factors as proximity to property, the operating pressure of the main or the extent to which the ground is sealed off between the property and the mains. Category A is the most hazardous and Category C the least hazardous. Appendix G The Importance of Conditioning Joints G.1 Introduction The changeover from town gas to natural gas increased natural gas leakage from the distribution system quite irrespective of losses due to fractures, break ages, corrosion, age or any other reasons which might lead to a breakdown of the system. Town Gas contained high levels of water vapour and aromatic hydrocarbons. The water vapour swelled the yarn in the lead yarn joints and the aromatic hydrocarbons swelled the natural rubber gaskets in mechanical joints. Natural gas is both dry and free of aromatics and, in addition, the average pressure of the natural gas system is double that of the town gas system. Each of these factors leads to an increase in-the expected level of leakage since conversion to natural gas. Pickering states that: "drying out factor is difficult to predict, but information from other countries indicate that leakage will increase, due to this cause, by at least a factor of 2. The combined effect of pressure and drying out is expected to increase the volumetric leakage by at least 4 times, and reports, again from other countries, suggests 5-8 times. Also, since the calorific value of natural gas is twice that of town gas, the thermal losses will be doubled. The resultant thermal loss could potentially, therefore, be a minimum of 8 times." Pickering lists the reports of leakage from shrinkage factors from other countries. In addition, he mentions that Chory (1969) had demonstrated that leakage would increase by a factor of 3 (to be multiplied by 2 for pressure and 2 for calorific value) for bell and spigot joints. Bowler (1987) also supports Pickering et al. Bowler states that the leakage rate due to the yarn drying out was more than double the previous level. This in turn was doubled because of the increase in pressure in the distribution system and doubled again for thermal content. It should be emphasised that this increase in leakage from a shrinkage factor of 2 (multiplied by 2 to obtain volumetric loss due to higher gas pressure) is a minimum. We have used this minimum in our low leakage case, and factors of 2.5 in our medium and 3 in our high leakage case. G.2 Leakage Rate from Joints To obtain a leakage rate estimate we used an average leakage rate reported in a study undertaken by the Gas Council in 1970 (Pickering e.t al, 1970). The study was to investigate what effect moving from Town to Natural gas would have on the leakage rate. The report concluded that in 1968-9 the low pressure system an average leaked 0.51 m3/h per km (17 ft3/h per 1000 yards) of main at a pressure of 12.5 mbar or a leakage rate of 0.67 m3/hr per km (20 ft3/h per 1000 yard) at a pressure of 15 mbar prior to conversion. The study measured 160 small sectors over 1330 km (828 miles) of main supplying a total of 80,000 consumers in 5 different gas boards. The volumetric loss, at a pressure of 12.5 mbar averaged 3.8 per cent of the gas carried by the mains. G.3 The Ability of Conditioners to reduce this Leakage Rate In order to minimise this type of leak, apart from renewing the whole system, the system must be conditioned. The success of this conditioning is a key determinant in methane leakage. It was decided that substances needed to be added to natural gas to replace the swelling properties of town gas. These introduced substances are known as gas conditioners and the effort to reduce leakage through adding these conditioners is known as gas conditioning. The constituents of town gas which swelled the rubber joints were trace aromatic hydrocarbons - benzene, toluene, xylene and so on. A conditioner containing these substances is known as distillate. It contains about 15-20 per cent of these aromatic hydrocarbons. Finding a conditioner for lead yarn joints has been more of a problem. It was discovered, after some time, that compounds with hydroxyl groups were the most effective and monoethylene glycol (monogol or MEG) was the best. However MEG and the other lead- yarn conditioners come in many forms all with different efficiencies. These are discussed in detail below. A review of the literature brings forth surprisingly few articles on conditioning. To complicate this already sparse information, the relevant papers (Clough 1989, Arnold et al 1984, Crompton et al, 1980, Bennett and Richards, 1983, King, 1977 and Pickering et al, 1970) were written at several years intervals and often contradict each other simply because of development of conditioners. It is therefore difficult to obtain a clear picture of what is the most effective conditioner and just how effective that conditioner is. G.3.1 Humidification This is generally regarded as a holding operation to prevent degradation of the lead yarn jointed system. Trials have shown that if the relative humidity of gas is maintained above 60 per cent the incidence of leakage is less than that from comparable systems which have not been conditioned. G.3.2 Aromatic Oil Vapourisation This is used in both medium and low pressure systems and is designed specifically for mechanical joints. G.3.3 Oil Fogging This is generally used on medium pressure mains where the travel of the fog droplets is assisted by the higher velocity of the gas. It can be either hot or cold. Because distillate is used with a 15-20 per cent content of aromatics, oil fogging is usually cold in order to keep vapour escapes to a minimum. Cold fogging has been very effective in reducing leakages from mechanical joints. G.3.4 Internal Vapour Phase Sealant G.3.4.1 Diethylene Glycol (DEG) DEG and humidification were the first widely used conditioners. Compton states that in the North West region from the end of the 1960s to 1975 humidification was used in the larger diameter mains and DEG pouring was used in the district mains. Despite this conditioning, leakages from the lead-yarn system increased during this time. In general, DEG was not successful in eliminating leaks despite some fairly good experimental results. For example, King states that DEG conditioning had a 72 per cent effectiveness over 600 days. This means that the leaks were cut by 72 per cent. Under this process, the yarn of the joint is conditioned by capillary climb from the reservoir of DEG. Capillary climb limitations restricts DEG use to mains below 12 inch diameter. G.3.4.2 Monoethylene Glycol (MEG) The ability of MEG vapour to reduce leakage is a function of many factors, including: condition and packing density of the yarn system temperature MEG saturation level initial leakage rate of the joints MEG is used either hot, with and external heat source, or cold. Hot methods use flash or sparge evaporators and cold methods are course droplet separation and direct atomisers. When a cold method is used, heat for the evaporation of MEG is supplied by the gas. MEG is injected into the main as fog which because of its small droplet size is rapidly evaporated into the gas. These hot and cold methods are described below: G.3.4.2.1 Flash Evaporator Glycol is sprayed onto a hot surface that is maintained at or above the boiling point of the liquid. The glycol output is varied with gas flow rate and mains temperature. G.3.4.2.2 Sparge Gas Evaporator A small stream of gas is passed through glycol heated to a temperature, below its boiling point, between 50-140øC. G.3.4.2.3 Coarse Droplet Separation An atomiser device gives a wide spectrum of droplet sizes and then separates the large diameter droplets back to the atomiser. The small droplets are transported to the gas stream. The output of the useful fog from the atomiser is low so multiple spray devices are often used together. G.3.4.2.4 Direct Atomiser into the Main Twin fluid atomisers can generate mists that can be directly injected into the gas stream without separating out the large droplets. This method is suitable for mains with diameters of 300 mm and above. All of these can types of gas conditioning can be undertaken with live mains, which means that gas continues to flow. The following means need to isolate the section of main for treatment. About 100 metres of main is isolated and cleared internally to get rid of rust and scale. The main is then pressurised to find any major leaks which are repaired at this point. The section is then filled for about 2 hours and then drained. It is suitable for medium and low pressure main and both lead yarn and mechanical joints. However, according to Pickering, its best results are on lead yarn at 2 bar, in other words medium pressure, and it is inadequate for low pressure. G.3.6 Bridge the Gap Remote controlled machinery is used to clean an isolated section of main, locate and clean joints and apply sealant. Appendix H Unaccounted For Gas (UFG) Every gas utility has a discrepancy between the quantity of gas input into the system and the quantity of gas registered at the point of sale. There are many possible causes of UFG including the following: Leakage from Mains and Services Metering errors due to temperature and pressure variations Metering errors due to defective meters Metering errors due to the type of meter used Condensation of water or hydrocarbons from the gas during transmission. A discrepancy will arise if the liquid is metered as a gas before the point of sale Gas used for commissioning new plant, running gas storage installations, running compressors and so on is lost because the gas used during such operations is not usually metered. Maintenance operations require the decommissioning of plant and equipment and gas may be lost, particularly when decommissioning high pressure pipelines. Gas venting from regulators and control instruments Unmetered gas contracts By-passing of meters for maintenance and repairs Illegal by-passing of meters or theft by customers Of these factors the most significant is leakage from mains and services. However the number of factors affecting the total UFG again highlight the problems associated with measurement of UFG and its constituents. Pickering et al (1970) state that between 1962-7 the UFG figure was relatively constant around 8.3 per cent. However, it should be noted that the figures represent UFG of town gas (see Table H.l). Table H.1 Unaccounted For Gas 1962-1967 (Omitted .. unscannable) [] TL: A Study of Leakage from the UK Natural Gas Supply System with Reference to Global Warming (GP) SO: Greenpeace UK DT: 1990 Keywords: atmosphere global warming climate change uk europe gas fuels energy greenpeace groups reports gp / [part 7 of 7] Appendix I Leakage Rates Finding average leakage rates has proved very difficult. We have used the average leakage rate described by Pickering because it was calculated over 1330 km over 160 sectors in 5 different gas boards. We discovered the following other references in the literature. However, these did not seem representative either because, in the case of the UK examples, of their short length or geographical position or, in the case of the Netherlands, we are unsure of the type and age of the system. After the changeover from town gas to natural gas the number of leaks strongly increased from a mean of 6 to about 20 leaks per kilo metre of cast iron mains. The leak size of the presently occurring leaks is on average of the order of 40 litres (1) per hour (Gaikhorst, 1971). In 27 km of low pressure main at Sherborne, the average leakage rate was 1.5 m3/hr (Crompton et al, 1980). The leakage rate was 1.1 m3/hr over 83 km of low pressure in Todmorden, North Eastern Gas (Crompton et al, 1980). References Abrahamson D, 1989, Relative Greenhouse Effect of Fossil Fuels and the Critical Contribution of Methane, paper presented to The Oil Heat Task Force, US. The Alphatania Group, 1989, Methane Leakage from Natural Gas Operations, London, UK. 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