Royal Commission on Environmental Pollution

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Executive Summary

The Royal Commission on Environmental Pollution is undertaking a major study on Energy and the Environment. As part of that study, six background papers addressing key issues have been commissioned. This is the second background paper in the series, and addresses Technical Innovation to Reduce the Adverse Environmental Impacts of Existing Energy Sources in the UK. Coal, oil, gas, nuclear power and large scale hydro-electric power are covered. Other renewable energy technologies are described in Background Paper 1. Energy efficiency technologies, which will reduce all the environmental impacts of energy use, are discussed in Background Paper 3. The environmental impacts are discussed in more detail in Background Paper 4.

The main energy-related activities which give rise to adverse environmental impacts, and the technologies which have the potential to reduce those impacts, are listed in Table E1. The most important impacts are caused by gaseous emissions from fossil fuel combustion, although water pollution from oil and coal extraction activities is also important. This paper discusses the technologies, indicates their effectiveness and cost, and discusses the factors influencing their uptake and deployment.

The environmental benefits of innovative technologies are generally not reflected in their market prices. In general, the main factor driving the uptake of environmental technologies is legislation and regulation. Limits on atmospheric emissions, discharges to water and waste disposal are set by the UK government, the European Commission and other international organisations such as the United Nations. In addition, many new developments are subject to a local or national planning processes or public enquiries, which can strongly influence the uptake of certain technologies. These restrictions will become increasingly important in future.

The main constraint on uptake of many environmental technologies is their high capital cost, and, for novel technologies, the perceived risk involved in such an investment. These constraints have been exacerbated by the privatisation and liberalisation of the UK energy markets. However, these barriers can be reduced to some extent by research and development to reduce costs and improve reliability, by demonstration and dissemination to reduce perceived risk and by other market support methods. An increasingly important driver for investment in new technologies is the potential for exports to developing countries.

This paper has identified certain key issues which might merit further consideration by the Commission during the course of its study. The key issues for each topic area are listed and ranked in rough order of importance in the final section of the report.

Table E1: Energy-related activities and technologies to reduce environmental impacts

Note: General energy efficiency improvements will reduce all of the above impacts, but these are discussed in another of the background papers for the Royal Commission, "Prospects for Energy Saving and Reducing Demand for Energy in the UK".

Contents

1 Introduction

2 Coal extraction, preparation and distribution

  2.1 INTRODUCTION
  2.2 UNDERGROUND MINING
    2.2.1 Methane
    2.2.2 Mine Water
    2.2.3 Subsidence
  2.3 OPENCAST MINING
    2.3.1 Methane
    2.3.2 Water
    2.3.3 Dust and Noise
    2.3.4 Visual Impact and Reclamation
  2.4 COAL PREPARATION
  2.5 COAL DISTRIBUTION

3 Oil and gas extraction

  3.1 Introduction
  3.2 Oil Spills and Leaks
  3.3 Oil Discharges
  3.4 Waste and Infrastructure Disposal
  3.5 Natural Gas Flaring, Venting and Own Use
  3.6 Release of CO2 and Hydrogen Sulphide
  3.7 Seismic Surveying
  3.8 Well Logging
  3.9 Improved Exploration and Production Techniques

4 Oil and gas distribution

  4.1 Introduction
  4.2 Oil Spills and Discharges
  4.3 Gas Pipeline Leakages
  4.4 Oil Pipeline Leakages
  4.5 Fugitive Emissions of VOCs

5 Oil refining

  5.1 INTRODUCTION
  5.2 CONTROL OF ATMOSPHERIC EMISSIONS
    5.2.1 Control of fugitive emissions
    5.2.2 Control of catalyst de-coking emissions
    5.2.3 Control of process plant emissions
    5.2.4 Control of fuel combustion emissions
    5.2.5 Control of flaring emissions
  5.3 CONTROL OF LIQUID AND SOLID WASTES
    5.3.1 Liquid waste
    5.3.2 Solid waste and sludges
      5.3.2.1 Land Farm for Oily Wastes
      5.3.2.2 Storage and Disposal of Non-oily Hazardous Wastes
      5.3.2.3 Groundwater Protection: BETX survey
  5.4 GASIFICATION OF REFINERY RESIDUES

6 Fossil fuel combustion for heat and power

  6.1 INTRODUCTION

  6.2 FUEL PREPARATION
    6.2.1 Coal preparation
      6.2.1.1 Removal of Inert Material
      6.2.1.2 Sulphur Reduction
      6.2.1.3 Chlorine Reduction
      6.2.1.4 New Coal Preparation Technologies
    6.2.2 Fuel oil quality
  6.3 COMBUSTION PROCESS MODIFICATIONS
    6.3.1 Low NOx Burners
    6.3.2 'Overfire Air' Injection (Furnace Air-Staging)
    6.3.3 Reburn (Furnace Fuel-Staging)
  6.4 END-OF-PIPE ABATEMENT
    6.4.1 SO2 Control Technologies
      6.4.1.1 Wet Scrubbing FGD
      6.4.1.2 Spray Dry Scrubbing
      6.4.1.3 Dry Sorbent Injection
    6.4.2 NOx control technologies
      6.4.2.1 Selective Non-catalytic Reduction (SNCR)
      6.4.2.2 Selective Catalytic Reduction (SCR)
    6.4.3 Combined NOx/SO2 Control Systems
    6.4.4 Particulate Control Technologies
    6.4.5 Carbon dioxide removal and storage
  6.5 MORE EFFICIENT HEAT AND POWER GENERATION PROCESSES
    6.5.1 Pulverised coal-fired supercritical/ ultrasupercritical steam cycles
    6.5.2 Fluidised Bed Combustion
    6.5.3 Integrated Gasification Combined Cycle
    6.5.4 High efficiency gas turbines
    6.5.5 HAT, IGHAT
    6.5.6 Direct coal-fired combined cycle turbine
    6.5.7 Kalina cycle
    6.5.8 Fuel Cells
    6.5.9 Magnetohydrodynamics (MHD)

7 Transport

  7.1 INTRODUCTION
  7.2 TRANSPORT FUEL MODIFICATION
    7.2.1 Gasoline
    7.2.2 Diesel
  7.3 ENGINE MODIFICATIONS
    7.3.1 Variable valve timing for petrol engines
    7.3.2 Direct injection petrol engines
    7.3.3 Optimised exhaust gas recirculation
    7.3.4 Improved direct fuel injection for diesel engines
  7.4 END-OF-PIPE SOLUTIONS
    7.4.1 Catalytic converters for petrol vehicles
    7.4.2 Catalytic converters for diesel vehicles
    7.4.3 Particulate traps
    7.4.4 Evaporative-emission controls for petrol vehicles
  7.5 ALTERNATIVE FUELS
  7.6 ALTERNATIVE DRIVE TRAINS
    7.6.1 Fuel cells
    7.6.2 Electric vehicles
    7.6.3 Hybrid vehicles

8 Nuclear fuel cycle

  8.1 INTRODUCTION
  8.2 NUCLEAR FUEL DISTRIBUTION
  8.3 NUCLEAR ELECTRICITY GENERATION
    8.3.1 Gas-cooled reactors
    8.3.2 Water-cooled reactors
    8.3.3 Advanced reactors
    8.3.4 Fast reactors
    8.3.5 Accelerator-driven systems
    8.3.6 Fusion
    8.3.7 Radioactive effluent processing
  8.4 NUCLEAR WASTE DISPOSAL

9 Large-scale hydro-electric power

10 Electricity transmission and distribution

  10.1 INTRODUCTION
  10.2 OVERHEAD POWER LINES

11 Factors influencing the uptake of technologies

  11.1 ENVIRONMENTAL CONCERN AND REGULATION
  11.2 INVESTMENT CONSTRAINTS AND ATTITUDES
  11.3 SECURITY AND DIVERSITY OF SUPPLY
  11.4 POTENTIAL FOR EXPORTS
  11.5 GOVERNMENT SUPPORT FOR R&D AND MARKET STIMULATION

12 Key issues

Footnotes

Appendices

APPENDIX 1 BIBLIOGRAPHY

APPENDIX 2 GLOSSARY

1. Introduction

The Royal Commission on Environmental Pollution (hereafter referred to as The Commission) is undertaking a major study on Energy and the Environment, which will review energy prospects for the 21st century and their environmental implications. As part of that study, a series of background papers addressing key issues have been commissioned.

This is the second background paper in the series, and addresses Technical Innovation to Reduce the Adverse Environmental Impacts of Existing Energy Sources. The existing energy sources in the UK are coal, oil, gas, nuclear power and renewable energy. Renewable energy forms the subject of the Commission's Background Paper 1 (Jackson, 1998) and will not be fully covered here, with the exception of large scale hydro-electric power which will be mentioned briefly.

Environmental impacts arise at each stage in the life-cycle of energy sources: fuel extraction, fuel processing, fuel distribution, fuel combustion, electricity generation and transmission. The environmental impacts arising at one stage of the life-cycle may sometimes be reduced by taking action at an earlier stage, e.g. removal of sulphur from coal or oil during the fuel processing stage can reduce emissions of sulphur dioxide from fuel combustion.

This paper is structured into sections which reflect the main fuel cycle stages of the existing UK energy sources:

• Coal extraction, preparation and distribution
• Oil and gas extraction
• Oil and gas distribution
• Oil refining
• Fossil fuel combustion for heat and/or power generation
• Transport
• Nuclear fuel cycle (fuel production, generation, decommissioning and waste disposal)
• Large scale hydroelectric power generation
• Electricity transmission and distribution

The environmental burdens associated with these activities are many and varied, including emissions of pollutants to air, discharges of pollutants to rivers and estuaries, groundwater pollution, loss of wildlife habitat and visual intrusion. The burdens lead to a range of environmental, ecological, health and social impacts. Table 1 gives an overview of the main environmental burdens arising in the UK from each of the above activities, focusing on atmospheric emissions. The total emissions arising from each activity are quantified where possible. For water pollution and waste disposal problems, only a qualitative indicator can be allocated. The table enables a rough "scoping" of which activities give rise to the most significant impacts. Burdens which are considered to cause significant impacts are highlighted in bold print.

The burdens arise at several stages: plant construction, routine operation, accidents, decommissioning of infrastructure and waste disposal. The relative importance of these stages varies between fuel cycles, for example, impacts arising from decommissioning are only considered to be significant for the oil exploration and nuclear fuel cycles, whereas for fossil fuel combustion it is the routine atmospheric emissions which are most important.

This study summarises the full range of technologies which can reduce these impacts (the impacts themselves are discussed in detail in Background Paper 4 (Eyre, 1998)). Particular attention is focused on the most serious impacts and the areas where technical innovation can contribute most: particularly reduction of emissions of the main greenhouse gases which contribute to global warming (carbon dioxide and methane), the gases which cause acid rain (sulphur dioxide and nitrogen oxides) and noxious emissions which can cause public health problems (volatile organic compounds, particulates, hydrocarbons and heavy metals).

A great variety of technologies are capable of reducing the environmental impacts of energy use, including:

• Reduction of fugitive emissions, e.g. leak detection, better seals, vapour recovery.
• Fuel cleaning and conversion, e.g. reduction of sulphur in oil and coal, reformulation of motor fuels, production of hydrogen or methane from other fuels.
• Technologies which permit use of a cleaner fuel, e.g. gas or electric vehicles.
• Cleaner and more efficient fuel combustion processes¹, e.g. low NO_x burners, integrated gasification cycles for coal or oil, fluidised bed combustion.
• Cleaner and more efficient electricity generation processes, e.g. combined-cycle, supercritical steam cycle, fuel cells.
• End-of-pipe abatement technologies to remove pollutants from gaseous or liquid discharges, e.g. flue-gas de-sulphurisation, liquid effluent treatment.
• Waste pre-treatment; improved design of landfills and nuclear waste repositories; re-use or re-cycling of redundant infrastructure.
• Mitigation activities, e.g. clean-up of oil spills.

Sections 2 to 10 of this paper cover the main energy-related activities listed above, from coal extraction through to electricity transmission. For each activity, the main environmental impacts are listed, and possible technologies to reduce these impacts are described. The paper aims to provide a brief description of each technology, an indication of its effectiveness at reducing impacts, consideration of its costs and mention of any adverse environmental side-effects. The state of development of the technology and the scope for deployment are considered, along with anticipated future technical developments.

In Section 11, the social, political, economic and market factors affecting the uptake of the technologies are discussed. Finally, in Section 12, the key issues which we consider might merit further consideration by the Commission during the course of its study are highlighted. A bibliography and glossary are provided in Appendices 1 and 2.

Table 1: Main Environmental Impacts from Energy Use (1995 data)

Source: National Atmospheric Emissions Inventory (Salway et al, 1997)

? An impact exists but is not quantified
X Moderate impact
XX Significant or potentially significant impact

2. Coal extraction, preparation and distribution

2.1 INTRODUCTION

This section covers underground mining, opencast (surface) mining, coal preparation and coal distribution. The main impacts from these activities are:

• Emissions of methane to air from coal mines
• Discharges of polluted water from coal mines
• Subsidence from deep mining
• Visual intrusion, dust, noise and loss of amenity/habitat from opencast mines
• Dust, noise and vehicle emissions from transport of coal
• Possible water pollution from coal storage heaps

Coal preparation can be used to reduce environmental impacts at the fuel combustion stage - this is discussed in Section 6.2.1.

Production of coal in the UK has been declining steeply for many years, due to competition from other fuels and from imported coal. In particular, over the last five years the use of gas for power generation (driven mainly by economic criteria) has eroded the market for coal. In 1997 about 48 million tonnes (Mt) was produced, compared to 130 Mt in 1980. This trend is likely to continue - the European Commission predicts production in the UK will be 12.5 million tonnes coal equivalent² (Mtce) in 2020, say 14.9 Mt of saleable coal (European Commission, 1996). There are, however, some commentators who think that production will have totally ceased by this date. The prospect of further contraction makes investment in capital-intensive environmental technologies by mining companies difficult to justify on simple financial criteria.

1997 production consisted of about 31 Mt deep mined coal and 17 Mt opencast. The production of opencast coal has increased slightly in recent years, and it forms an increasing percentage of overall coal production - from 12% in 1980 to 35% in 1997. Deep mining and opencast mining have different environmental impacts and therefore different potential abatement technologies.

Traditionally, opencast mining costs have been less than deep mining, although the differential is narrowing. Opencast coal can be produced with a lower ash content, and generally has a lower chlorine content, than deep mined coal. It is therefore often used to 'sweeten' deep mined coal and the mining companies always stress the importance of this role, arguing that without it some of their underground production would be 'unsaleable' and stressing the importance of providing continued employment for miners. However, some commentators claim that only 9Mt of opencast coal is currently required for sweetening (ENDS, 1997a). By contrast there is growing public concern about the local environmental impacts of opencast mining, which has prompted a review of government planning policy (DETR, 1997). On balance, the continued relative growth of opencast mining seems unlikely in the short to medium term.

Many of the impacts arising in this sector can be controlled with relatively simple technologies. These are described briefly for the sake of completeness. Technical innovation may in future play a part in the treatment of coalbed methane emissions and minewater effluent (sections 2.2.1 and 2.2.2), although the techniques mentioned here are relatively untested and further development is necessary.

2.2 UNDERGROUND MINING

Methane is released from hard coal during the destressing and fracturing of coal as it is mined. Typically, for UK underground mines, 10.3 kilograms (kg) of methane is emitted from the mining of each tonne of coal (including emissions during transit and storage). Current UK emissions from deep mining therefore amount to about 320 kilotonnes per year (kt/y), 9% of total UK methane emissions. An analysis of current and projected methane emissions from coal mining globally is given in Williams et al (1996).

To the mining engineer methane is a potential hazard as it can form an explosive mixture with air. Normal UK practice, therefore, is to 'drain' at least part of this gas before it can enter the ventilation air stream. In a working mine, this can be done by drilling a series of inclined holes into the strata above the coal seam, and applying mild suction pressure to drain off the methane into a system of pipes. Alternatively, methane can be pre-drained by drilling boreholes from the surface before a new mine is excavated. This technique is deployed in the USA, but is only suitable for areas with heavy gas and very porous strata, to allow diffusion of the methane into the borehole. Interest is also increasing in "virgin methane extraction", i.e. drilling for methane as a fuel in its own right, although UK geology is less favourable than in the USA.

The collected methane is either released at the surface or at a safe location underground, or in some cases the gas is burned for energy, either for electricity generation at the mine or supply of the gas to local industry. It is effectively a 'free fuel', the underground collection costs being regarded as a necessary part of the mining operation. Nevertheless the utilisation rate is low. As a rule of thumb, for the UK, one third of the methane emitted is collected and only one third of this is actually used. This is partly due to lack of local markets, and partly because of the low methane content of some of the collected gas. UK legislation limits utilisation to gas containing 40% or more methane, although exceptions can be obtained down to 30%. This is because methane is explosive when mixed with atmospheric air in the range of 5% to 15%. Further information on mine methane control is given in Creedy et al (1997).

Emissions of methane from coal extraction are not currently regulated. This may change following the recognition of methane as an important greenhouse gas. However, methane emissions are already declining steeply due to the reduction in mining activity. It would be possible, by improved technology, to increase the percentage of gas collected, but it is unlikely that such systems would be justified on simple economic grounds. They would have to be driven by environmental or health and safety requirements.

In the past, mine methane was sold to a wide range of local industries (Goode, 1994). This is likely to be more difficult in the future as the prospects of further mine closures will make it difficult to convince customers of the long-term availability of such gas. The comparatively low calorific value of the gas makes it uneconomic to transport over long distances. The best utilisation option, therefore, is likely to be electricity generation at the mine, for own use or export. Generation options include reciprocating engines, open-cycle or combined cycle gas turbines. Typical pay-back times are between three and five years. Further information is given in Bennett et al (1995) and Creedy et al (1997).

The above energy recovery options require a gas containing at least 30% methane. However, over 70% of the methane emitted from mines is extracted in very dilute form in the exhaust ventilation air, typically containing less than 1% methane. There would, therefore, be considerable benefits if this gas could be utilised in some way. It can be used instead of 'normal' air in boilers or internal combustion engines and this can lead to a fuel saving of up to 7%. However, the quantity of air and the costs of transporting this air, even for very short distances, make the economics difficult. There is, however, another option currently under development. This is the Vocsidizer system which passes low concentration methane through a heated gravel bed (Stoehr, 1996). If the air contains more than about 0.5% methane then there is a net heat generation due to catalytic oxidation of the methane, so pipes within the bed can be used to generate steam or hot water. The system was originally developed for destroying volatile organic compounds (VOCs) produced during paint spraying. At low concentrations of VOCs, it was discovered that methane had to be added to make the reaction self-sustaining. However, its use for mine air would involve an order of magnitude scale-up in the size of the system and the volumes of gas treated. The technology and economics for this scale still have to be proved.

2.2.2 Mine Water

Most mines have an inflow of water which has to be pumped out. Some of this can be used for dust suppression underground or in the coal preparation plant. Since the water comes from underground aquifers and is only in contact with the mine workings for a limited time there are usually no particular problems with high acidity or low oxygen content, although some basic treatment may be necessary before it is released to neighbouring watercourses³.

The problem with mine water comes after mines are closed. Once the mine is abandoned, and the pumps are stopped, the water level gradually rises. This water is in contact with the exposed mine surfaces for extended periods and can therefore become acidic and contaminated with iron by reacting with pyrite (iron sulphide) in the remaining coal. Many UK mines are interconnected, either by roadways or by zones of permeable strata, so this water can eventually be discharged at the surface at a location remote from its original source. This can result in severe river pollution, causing large scale fish kills, and the source of this pollution may not be immediately obvious. There is also a danger that aquifers used for water supplies can become contaminated. Such pollution will become an increasing problem, especially in areas, such as Scotland and the North East, where underground mining has substantially ceased (ENDS, 1997b). Apart from the pollution problem, the fluctuations of groundwater level caused by the initial pumping and then the abandonment can cause problems in their own right (such as watercourses drying up or unexpected flooding and waterlogging), especially when many mines in a region are closed down in a short time period.

Legal requirements are currently limited. The only offence is if a mine owner "knowingly permits a discharge of contaminated water". In the case of abandoned mines, it is difficult to identify the owner, since many of the workings date back to the period before the mines were nationalised in 1947. The Coal Authority, which was formed to take over the residual, post-privatisation responsibilities of British Coal, has only a non-statutory obligation (dependent on the provision of DTI funding) to assist with minewater pollution problems arising from pre-nationalisation mines. This legal position will change in due course. The Environment Act 1995 puts the responsibility for pollution on the mine owners, but there is a grace period, so this will only apply to mines abandoned from the year 2000 (ENDS 1997b). An increasing number of mines could be abandoned as this deadline approaches.

Because the problem, or perhaps the realisation of the problem, is comparatively new, there is only limited experience of treatment methods. Options include aeration to improve the oxygen content (needed to sustain plant and animal life) and treatment with limestone or in reed beds to neutralise the acidity. Reed beds can also help to remove trace metals. Another option which has been suggested is in-situ biological de-acidification using bacteria to neutralise the acidic water in the mine.

The pollution is generally worst when it first occurs and tends to decay thereafter. This is because the 'first flush' arises from pyrite oxidisation products which were flushed into solution during the regional water table rebound. There is however likely to be residual pyrite oxidation resulting from seasonal water table fluctuations. This is because the reaction requires the presence of oxygen. It does not therefore take place in the deeper flooded parts of the mine. This variation can make it difficult when designing any treatment plant, since it is necessary to make assumptions as to projected flows and pollution loadings. Any methods which could be used to maintain the water level nearer constant - perhaps some controlled draw-off method - or to reduce the air/oxygen content would also be beneficial.

2.2.3 Subsidence

Extracting coal by underground mining inevitably results in surface subsidence, although this is generally significantly less than the thickness of coal abstracted. This can cause damage to surface buildings and services, and problems with watercourses. Control of subsidence can be a condition of a mine owner's operating licence - at Selby, the surface subsidence is not allowed to exceed one metre. Subsidence can be reduced by 'stowing' the caved area, however this is very expensive and only partially effective. This extra cost would make UK mining even less competitive compared with imported coal.

On the positive side, subsidence can be predicted comparatively accurately. Also, in the case of longwall mining - the normal method used in the UK - it occurs comparatively soon after extraction. So it is possible to take remedial action in the knowledge that further damage is unlikely. The problem is differential subsidence, rather than subsidence itself. Buildings can be designed to accept reasonable amounts of subsidence. For example individual detached houses are far less susceptible than a terrace and raft foundations - rather than normal strip ones - give increased protection⁴.

2.3 OPENCAST MINING

Methane emissions from opencast mining are much less than those from deep mining. The coal seams are near the surface, so most of the original methane has been released over the millions of years since the strata were laid down. Remaining methane goes to the atmosphere where it is so quickly diluted by the ambient air that its presence is not detected. There is no reasonable way of preventing this release. About 0.34 kg of methane is emitted from the mining each tonne of opencast coal (Salway et al, 1997). Current UK emissions from opencast mining therefore amount to about 6 kt/y, only 0.15% of the UK total.

2.3.2 Water

The plan area of an individual opencast mine can mean that it receives a considerable amount of rainfall and this generally finds its way to the bottom of the pit; there can also be inflows from permeable strata overlying the coal. This then has to be pumped out and disposed of. Most UK opencast mines have a comparatively short operating life - five years is typical. This can mean that the water disposal facilities provided are less sophisticated than those at underground mines, for financial reasons.

2.3.3 Dust and Noise

Dust and noise are important local impacts from opencast mining. Dust can be controlled by the watering of haul roads and by the prompt reclamation of worked-out areas. Noise comes from machinery, particularly diesel trucks as they climb up out of the pit, and from blasting. Machinery noise can be limited by strategically placed earth mounds or other sound baffles. Most licences place limits on the size and timing of blasting.

2.3.4 Visual Impact and Reclamation

Two of the most emotive aspects of opencast mining are the visual impact during operation and the way that the site is reclaimed afterwards. It must be remembered that some sites are within a few hundred metres of houses. The visual impact can be improved by using the top soil stripped from the area mined to form mounds or berms, especially on the sides nearest to habitation. This material needs to be kept separate for use in the final reclamation. The mounds should be grassed, and possibly planted with trees or bushes. This makes them more attractive and also prevents wind erosion. Where possible, progressive restoration should take place during the life of the mine. This is fairly straightforward if the operation is a 'strip mining' one, typically using a dragline for overburden removal. In this case the overburden from one strip is placed in the void from the previous one and covered with topsoil, which has been stripped separately. This only leaves the final cut to be attended to. Where the operation is basically a conical open-pit, generally excavated using a combination of power shovels and large off-highway trucks, the overburden will generally have to be temporarily dumped outside the pit.

It is not generally feasible to restore the ground to the original contours, because of the amount of material that has been removed. The objective should therefore be to achieve pleasing contours. In some cases the problem of shortage of material can be overcome by making part of the area into a lake or other water feature, which can provide a useful wildlife habitat. One obvious way of overcoming the shortage of fill material is to use the pit for the disposal of domestic refuse or other wastes. This is likely to be unpopular with local residents, who will feel that they have been subjected to enough inconvenience during the life of the pit. Reclamation treatment, e.g. drainage, fertiliser application, lime application, needs to be continued for some years after mining, until the land has recovered its natural fertility.

The preceding discussion focuses on the negative aspects of opencast mining. It is sometimes claimed, however, to have a positive benefit for the reclamation of derelict mining areas. These include the sites of early shallow underground mines where considerable amounts of residual coal remain. The revenue from mining the remaining coal can finance the reclamation of the general area, producing a net environmental benefit by restoring the fertility and amenity value of the land, although in some cases opponents argue that the "derelict" land already has significant amenity and wildlife value (e.g. ENDS 1997a).

2.4 COAL PREPARATION

The objective of coal preparation is to reduce the amount of inert material and other impurities from the 'run-of-mine' coal. This both increases the market worth of the coal and potentially reduces the environmental impact of the subsequent combustion of the coal. It is liable, however, to introduce minor environmental impacts of its own, due to water use, disposal of waste, storage in stockpiles and loss of coal to waste. This section discusses methods of reducing these impacts. The use of coal preparation as a means of reducing emissions during fossil fuel combustion is discussed in Section 6.2.1.

Water use: Conventional coal preparation uses considerable amounts of water. Much of this can be recirculated, but some will have to be discharged to drains or waterways. Provided it is properly treated first (e.g. by filtration) then this should have minimal environmental impact.

Waste disposal: Coal preparation generates considerable quantities of solid waste, containing the rejected ash and inseparable coal. Some of the coarse material may be used for low grade construction purpose, such as road sub-base material. The remainder must be disposed of in landfill sites. Coal preparation produces considerable amounts of slurry, consisting of fine waste, plus some coal, in water. This was traditionally discharged into lagoons where it dried out eventually. In the meanwhile it was an eyesore and a potential hazard to children and animals. This would not be acceptable at a new coal preparation plant, so current best practice is to dry the slurry into a 'cake' using filter presses, vacuum filters or centrifuges. It can then be safely disposed of.

Stockpiles: Stocks of coal are maintained at the mine, some in open stock piles. The environmental implications are considered under "Coal Distribution" (Section 2.5).

Loss of coal to waste: No coal preparation process achieves perfect separation, so there is inevitably some loss of coal to the waste stream. This has an environmental impact just to the extent that additional coal must be mined to make up for this loss.

2.5 COAL DISTRIBUTION

Coal distribution includes transport and storage. For UK coal, this covers transport from the coal mine/preparation plant to the user. For imported coal, this covers discharge at UK ports and transport from the port to the user; in this case the earlier portions of the chain produce environmental impacts outside the UK. In the UK, most of the coal is transported by rail (diesel locomotives), with some by road or inland waterway⁵. Technologies to reduce emissions from road transport vehicles are discussed under Section 7.

There are some minor impacts specific to coal transport and storage. Dust can arise from coal loading, transport in open rail wagons and storage of pulverised coal in uncovered ground stockpiles at power stations. In general, dust from loading and transport is not much of a problem in the damp UK climate, but if necessary it can be controlled by spraying with water or with an emulsion that 'holds' the fine particles.

Stockpiles are generally of 'whaleback' shape and have the surface compacted to maximise water run off and minimise the risk of spontaneous combustion. The long-term (strategic) piles are often given a surface coating to improve weather protection and to minimise wind-borne dust. Such water as does percolate though the pile may well become acidic due to the sulphur and chlorine content of the coal. It is therefore important that all run-off from coal stockpiles is treated before discharge to drains or watercourses.

Spontaneous combustion has traditionally been a problem in coal storage. There are two ways of minimising the risk. One is to ensure that there is an adequate air flow through the coal, so that hot-spots cannot occur. This is generally only achievable with "sized" (lump) coal and is not, therefore, relevant to power station stockpiles of pulverised fuel. The second is to go to the other extreme and to compact the body of the pile and preferably also to seal the surface. This prevents the ingress of oxygen, so that heating cannot reach the critical stage. While it is necessary to monitor stockpiles for incipient heating, if the above precautions are taken spontaneous combustion should not be a problem with UK coals and UK climatic conditions. Problems may occur with some imported coals, for example Indonesian, which are particularly susceptible to spontaneous combustion.

3 Oil and gas extraction

3.1 INTRODUCTION

The main phases of oil and gas extraction are exploration and development, production and abandonment. The main environmental impacts of these phases include:

Environmental and safety legislation has been a major driver of the industry in recent years, and considerable resources have been devoted to developing technologies to reduce these impacts. Some of these technologies are specific (e.g. water treatment to reduce discharges of oil), and some reduce the impacts by offering a general improvement in the efficiency of exploration and production, meaning that fewer wells have to be drilled to recover a given amount of oil.

Offshore production in UK waters is a substantial source of methane and carbon dioxide. Although not regulated at present, it may attract future scrutiny from a greenhouse gas viewpoint. The oil industry world-wide is driven by the challenge of developing ever smaller, deeper and more complex fields as reserves decline, and simultaneously by the pressure to reduce costs in an increasingly competitive global market. In the UK, the industry is approaching a major re-investment programme associated with a move in production from the shallower waters of the North Sea into the deep waters off Shetland, and this will place pressure on the funds available for environmental improvements. However, the challenges facing the industry can be viewed either as opportunities or as threats, and only those companies which respond flexibly by the innovative development of new technologies and strategies to meet changing market needs will succeed in the long term (Smith, 1997).

3.2 OIL SPILLS AND LEAKS

Oil spills from offshore operations accounted for the accidental release of 127 tonnes of oil in 1996 (DTI, 1997). This is fairly insignificant compared to routine oil discharges (see below), although oil spills can do more local damage when slicks are formed. Spills can be detected from surveillance flights using infra-red and ultra-violet detectors and side-looking airborne radar. Technologies to minimise damage from spills include sensitive flow meters for detection of leaks, blow-out preventers and remote sensing to locate slicks. Oil that has been spilled can either be dispersed or recovered using specialised equipment. Better operational procedures play a key role in reducing the impact from oil spills, and current legislative changes will require the development of site-specific contingency plans rather than relying on generic plans.

As smaller and deeper fields are developed, subsea production (where the wellhead and associated equipment is installed on the seabed instead of on a floating platform) will become more popular. There is an increased risk of undetected leaks from the valves and joints of subsea installations, because more valves and joints are underwater and also the products are transmitted in underwater pipelines for long distances to the nearest platform for separation and treatment. More sophisticated leak detection systems will be required because multiphase flow is involved, i.e. the oil, gas and water flow together in the pipeline. For single phase flow (where water, oil and gas are separated at the wellhead and sent on in separate pipelines) "mass balance" systems can be used, which monitor the pressure, temperature and flow rate at each end of the pipeline to ascertain whether material is being lost. However, current flow meters are not sensitive enough to detect leaks in multiphase flow systems, due to the greater variability of multiphase flow conditions. The development of improved leak detection equipment is likely to depend on the strictness of environmental legislation.

3.3 OIL DISCHARGES

Oil is discharged to marine and estuarine waters during exploration and production of oil and gas. In 1996, 3826 tonnes were discharged on drill cuttings and 5660 tonnes with produced water. Produced water is defined as the water produced in well fluids - including both the water released from oil-bearing formations and the sea water injected to enhance oil recovery. As well as being contaminated with oil, it can contain heavy metals and production chemicals such as corrosion inhibitors, viscosity modifiers and biocides.

Legislation currently limits the oil content of discharged produced water to 40 parts per million (ppm) oil, not including oil dissolved in the water. There is pressure to reduce this limit to 30 ppm or to zero, requiring improvements to water clean-up equipment and processes. At present, produced water is separated from the oil by gravity separators or hydrocyclones. Other chemicals are not removed by this process and are not currently regulated. Despite improvements to treatment technology, the amount of oil discharged from produced water is likely to increase in future due to increased activity in the North Sea and the increasing age of North Sea reservoirs (as reservoirs become depleted, more seawater is injected to enhance oil recovery). The industry is therefore investigating techniques for re-injecting produced water into rock formations.

Oil from drill cuttings has decreased significantly over the last decade, as oil based drilling muds are being phased out - since 1992 the maximum oil content of muds has been reduced from 15% to 1%. Alternative water-based, ether-based and ester-based drilling muds, which are more biodegradable than oil-based muds, are being developed. For enhanced oil recovery from depleted reservoirs, the use of air, natural gas and mud/water foam is being explored. Other technologies to reduce environmental impacts include closed loop mud treatment (i.e. cleaning and re-use); re-injection of produced water and drill cuttings into rock formations, and development of more benign chemical additives, e.g. corrosion inhibitors, surfactants and biocides. As drill muds are expensive, the operators have a financial incentive to maximise recovery and minimise losses into the environment.

3.4 WASTE AND INFRASTRUCTURE DISPOSAL

Drill cuttings which are contaminated with oil have to be disposed of. Presently these are disposed of at sea. The limit on oil contamination has recently been reduced from 150g oil per kg cuttings to zero. Cuttings disposed of onshore are limited to 50g/kg. The industry is investigating the possibility of grinding cuttings to a slurry then re-injecting them into suitable rock formations, but technical difficulties have not yet been resolved. In addition to the oil content of the drill muds, the muds and drill cuttings have a detrimental effect on the environment due to smothering of benthic lifeforms. In general such consequences are limited to within a few kilometres of the well.

The recent controversy over the Brent Spar has highlighted the problem of disposal of redundant infrastructure. This will be a significant issue in future as North Sea oil fields begin to be abandoned - around 450 structures will be taken out of use in the next 20-30 years. Alternative options include disposal by sinking to the sea bed, with preliminary clean-up if necessary, re-use as an artificial reef, or transport to land for disposal and/or recycling (Coleman, 1997). The evaluation of these options requires a complex balance between the social and environmental costs and benefits of each method. The energy used for towing the structure to shore and for dismantling, re-using or recycling the materials must be balanced with possible impact of marine disposal, the energy and raw materials saved by recycling and the jobs created. Evaluation is hindered by a lack of knowledge about the potential impact of infrastructure disposal on deep sea flora and fauna. Important factors to be considered include the transport distances involved, the depth and geological stability of the proposed disposal site and the importance of the area for fishing (NERC, 1996). Although a case-by-case evaluation is necessary, the cumulative impacts of dumping large numbers of structures should be taken into account. In the case of the Brent Spar, it has recently been announced that the structure will be re-used as sections of a quay in Norway.

The problem of redundant infrastructure may be mitigated to some extent by the trend towards subsea production and "minimum facilities", whereby the amount of equipment needed to produce oil and gas is minimised. However, a longer term strategy could well be based around designing structures at the outset specifically for re-use or recycling. The European Commission has conducted an extensive study (EC, 1997) and recently announced an initiative to support sustainable disposal of offshore platforms (EC, 1998a), as well as adopting a recommendation that sea dumping of used platforms should cease (EC, 1998b).

3.5 NATURAL GAS FLARING, VENTING AND OWN USE

Natural gas is flared (burnt off) or vented where it cannot be used or captured. This may be where small quantities of gas are associated with oil, and transport to land is not economic. In such cases the gas is generally used for energy on the platform or on nearby platforms where possible, and the remainder is flared, producing CO₂, NO_x and some methane emissions. Gas may also be either flared or vented when purging of gas pipes is necessary for routine or emergency maintenance. Flaring is preferable to venting because 98% of the methane in natural gas is converted to CO₂, but it may not always be possible for safety reasons. Although only small quantities are vented, venting was responsible for over 70% of methane emissions from offshore oil and gas operations in 1991. Both flaring and venting emissions could be reduced by better design of equipment and planning of operations, more efficient flares, and more recovery of gas for combustion or compression for subsequent energy use. This could achieve methane reductions of up to 40% (Woodhill, 1994).

In 1996, 2.4 billion cubic metres of gas was flared at offshore fields. This was about 5% of total gas production. In 1991 the value of the gas flared was around £120 million (Woodhill, 1994). Gas use for pumping, drilling and other operations on platforms was 55 terawatt hours (TWh), 5.2 billion cubic metres, in 1996 - around 8% of all natural gas use.

3.6 RELEASE OF CO₂ AND HYDROGEN SULPHIDE

CO₂ and hydrogen sulphide (H₂S) can be released during production from reservoirs. The amounts involved are difficult to quantify although CO₂ can form up to 20% of the production stream, with a more usual range of 1-4%, and H₂S is typically 30 ppm in those fields where it is present. The CO₂ is stripped from the gas stream by solvent washing and discharged or alternatively can be re-injected into the well.

3.7 SEISMIC SURVEYING

Seismic surveying involves transmission of shock waves through the sea and the rocks beneath the seabed. In the past, explosives were used but these have been replaced with air and water guns. These emit shock waves only, without noise, and cause less damage to marine life. However, these shock waves can still be harmful and could interfere with the communication systems of marine fauna or with the ballast systems of certain fish species. This is the subject of ongoing research. The primary mitigation measure is to undertake an environmental characterisation to identify seasonality in the sensitive species and phase the surveys accordingly.

3.8 WELL LOGGING

The only significant environmental impact of well-logging activities is the occasional loss of radioactive tools, which are generally then cemented into place in the borehole and abandoned. This problem is being addressed through the development of non-nuclear alternatives or lower-intensity alternatives; through the use of radiation generators instead of chemical sources, and through developing better retrieval techniques for lost tools.

3.9 IMPROVED EXPLORATION AND PRODUCTION TECHNIQUES

A variety of techniques which allow more accurate location of hydrocarbon prospects and more efficient extraction of oil and gas from reservoirs effectively reduce the environmental impacts by decreasing the number of wells which have to be drilled. These techniques include 3-D seismic surveying, horizontal drilling of many wells from a single rig, faster computer processing of seismic and borehole data, remote sensing, vertical seismic profiling, measurement while drilling and borehole tomography (Smith, 1997).

Improved Oil Recovery allows greater yield from each field, and thus has benefits in promoting the sustainability of resources. However, it may involve the drilling of additional wells, the use of additional energy for drilling and pumping, and the use of harmful chemicals such as surfactants (these encourage mobility of the oil by reducing its surface tension).

4. Oil and gas distribution

4.1 INTRODUCTION

Oil and gas distribution involves transport of crude oil and gas from the production platform to the onshore terminal; processing of gas to remove water and hydrogen sulphide; transport from the terminal to the refinery; transport of processed oil products from the refinery to the user, and onshore distribution of natural gas in pipelines or LPG cylinders. The various stages include transport by tanker, pipeline, road, rail and inland waterway. The main environmental impacts are:

• oil spills and ballast water discharges from tankers
• leakage of natural gas (methane) or oil from pipelines
• leakage of volatile organic compounds during oil tanker loading and vehicle refuelling
• atmospheric emissions of methane and sulphur dioxide from gas processing plant (generally controlled by flaring and sulphur recovery plant, see Section 5.2.3)
• emissions from vehicle engines during road, rail and sea haulage of crude oil and oil and gas products (covered under Section 7).

4.2 OIL SPILLS AND DISCHARGES

The probability of a tanker accident leading to an oil spill can be reduced by relatively simple measures, including the use of double hulled tankers, provision of more emergency tugs, routing to avoid sensitive areas and development of more sophisticated navigation aids. However, these measures have been poorly implemented in the UK (ENDS 1996). The upgrading of the tanker fleet is hindered by the international nature of the shipping industry, and the large number of ageing vessels. There is a danger that double hulled tankers would simply not be used, as shippers would charter cheaper, older vessels instead. Technology to clean up spills is also important (booms to contain spills, chemical dispersants to assist breakdown of slicks, etc.) although weather conditions can hamper the timely deployment of these techniques following an accident.

Tankers fill some of their empty oil tanks with ballast water for the return journey. This is then discharged into the sea. Discharge is supposed to stop when the oil-water interface has been reached, or when the concentration of oil in the discharged water exceeds 50 ppm. However, there is a high level of non-compliance with these procedures.

4.3 GAS PIPELINE LEAKAGES

Gas is transported from the six UK gas treatment and processing facilities to the end user in two stages: transmission in high pressure pipelines to an "offtake" station, followed by pressure reduction and then distribution at lower pressure in underground gas mains.

Transmission pipelines are made of carbon-manganese steel, with welded joints and anti-corrosion coatings. They are inspected by passage of intelligent robotic inspection devices (known as PIGs) through the pipeline without interrupting the flow of gas. PIGs inspect pipeline interior walls for corrosion and defects, measure the interior diameter of a section of pipe, and remove accumulated debris. Anomalies measured in the magnetic field of the pipeline wall signal defects which need to be repaired. British Gas has been at the forefront of developing new inspection tools for PIGs such as ultrasound technology (GRI, 1996). Cathodic protection is also applied to newer sections of pipelines, whereby an electric current is passed through the pipeline to inhibit corrosion. Very little leakage occurs during gas transmission. With the liberalisation of the gas market, standards for the water and hydrogen sulphide content of gas transmitted in pipelines may be relaxed in order to allow new shippers to enter the market. Pipeline operators may need to use improved corrosion-resistant materials and inspection and repair technologies to cope with this, but this should not pose a major problem because the technology exists already in the offshore production industry.

Significant gas leakage arises from the distribution of gas in underground mains. The older mains are made of cast iron, which was later replaced with ductile iron or steel, and then, since the 1970s, polythene. Most of the leakage occurs from the old cast-iron pipes. Leakage surveys are based on sensitive gas detection instruments, coupled with the odorising of gas to enable detection by members of the public. New instruments for optical detection of methane which will allow cheaper and quicker leakage surveys are being tested in the USA (GRI, 1997). Methane leakage from gas distribution was estimated to be around 380 kt of methane in 1991 (1% of throughput). Since then, emissions have declined to 359 kt methane in 1995 (Salway et al, 1997) as ageing cast iron distribution pipes have been replaced with new plastic pipes. Transco intend to reduce leakage by 20% from 1992 levels by the year 2000, through a range of measures including replacement and service of gas mains, and pressure reduction and gas conditioning (addition of water to reduce leakage from ball and spigot joints) in the older, cast-iron parts of the system. Leakage from gas storage systems (salt caverns, liquefied natural gas storage, rough offshore storage) is also being addressed, although this is fairly insignificant.

4.4 OIL PIPELINE LEAKAGES

In the UK, most crude oil is transported by pipeline to the nearest onshore terminal, and then by coastal tanker if necessary to reach the nearest refinery. Leakage from oil pipelines can be reduced either by better leak detection or by improved pipeline construction. Leaks can be detected using flow meters (see Section 3.2) and by defect assessment using technologies such as strain meters and assessment of buckling/upheaval. Pipeline integrity can be improved by using stronger or more corrosion-resistant materials, improving welding techniques, and improving pipeline laying techniques to avoid stressing joints and welds.

4.5 FUGITIVE EMISSIONS OF VOCS

Volatile organic compounds (VOCs) leak into the atmosphere during loading/unloading of oil tankers and during other operations on oil and gas platforms and at oil and gas terminals. It is difficult to control these "fugitive emissions", but crude loading/unloading and transportation is affected by the forthcoming International Maritime Organisation (IMO) Conference on Marine Pollution (MARPOL) Annex 6 regulations. Some companies are already investing heavily in this area (costs can be over £100 million each).

VOC leakage during gasoline distribution and vehicle refuelling is regulated through the European Commission's "Stage 1 Directive" which requires vapour recovery at all transfer points in gasoline distribution (EC, 1994), and the "Stage 2" directive controlling vapour recovery for vehicle refuelling operations.

5. Oil refining

5.1 INTRODUCTION

The main environmental impacts of oil refining are:

• atmospheric emissions, including CO₂, SO₂, NO_x and VOCs - direct or from energy use
• liquid effluent
• residue, waste and sludge disposal

Oil refining is energy-intensive - approximately 300 PJ were consumed in 1994, compared to 1200 PJ in the whole of UK industry. However, much of the energy consumed comes from by-products of the refining process such as refinery gas and residue. Refinery processes tend to be well integrated so that waste heat from one process can be used in another process, and fuel efficiency is therefore high.

This section covers technologies to reduce the adverse environmental impacts of refinery processes: gaseous emissions, liquid effluent and solid waste. The use of refinery technologies for reducing environmental impacts in other sectors by producing cleaner fuels (e.g. removing sulphur in fuel oil or diesel) are covered in Sections 6.2.2 and 7.2.

Crude oil is initially split into three fractions by distillation at atmospheric pressure: a light fraction which is refined to make gasoline and kerosene; a middle distillate which is refined to make diesel and gasoil, and a heavy fraction. The heavy fraction is then distilled in a vacuum to obtain a further yield of light or middle distillate (known as vacuum gas oil). The residue of the vacuum distillation is then "cracked" to make fuel oil, i.e. it is heated to break down long hydrocarbon molecules into shorter molecules. This can be done either in a fluid catalytic cracker (FCC), which passes the oil through a fluidised bed of catalyst, or in a hydrocracker where the oil is reacted with hydrogen. The residue remaining after cracking can be reduced using deep residue conversion, partial oxidation or gasification, yielding a fuel gas or hydrogen for use elsewhere in the refinery plus other products such as tar.

Increasing demand for light and middle distillate for transport fuels, coupled with a decline in the demand for fuel oil, has created pressure to maximise the yield of light fractions. North Sea oil is much lighter than most imported oil, and has less sulphur and a lower content of metals (e.g. nickel and vanadium). It is therefore more easily distilled and leaves less residue than other oils. As North Sea reserves become depleted and reliance on imports increases, refineries will find it much harder to meet environmental legislation and the demand for lighter products (Wiltshire, 1995). Technologies to utilise heavy fuel oil and refinery residues at minimum environmental impact may thus become more important in future (see Section 5.4).

Refinery operators tend to be large multinational oil companies with both upstream and downstream operations. They already face pressure to reformulate gasoline and diesel in line with the draft EC Directive on fuel quality, as well as environmental and economic pressures both upstream and downstream from refineries. These include current and possible future legislation of greenhouse gas emissions from offshore production (see Section 3), and regulation of vapour recovery during gasoline distribution (see Section 4), as well as investment in deep water exploration (see Section 3). In addition, profit margins are currently low due partly to overcapacity in the European refining industry (EC, 1996). All these factors affect the availability of capital for further investment, and hence the rate at which additional environmental measures might be introduced.

5.2 CONTROL OF ATMOSPHERIC EMISSIONS

Refineries are a major source of atmospheric emissions of VOCs, and a significant source of sulphur, reduced sulphur compounds and oxides of sulphur. They also emit carbon monoxide (CO), carbon dioxide (CO₂), ammonia and nitrogen oxides, and are a minor source of toxic VOCs such as benzene and 1,3-butadiene, methane, toxic organic micropollutants (dioxins, PAHs), heavy metals, particulates and odour. The main sources of emissions are:

• Fugitive losses of VOCs from leaking pipes, pumps, valves, storage tanks, etc.
• De-coking of catalysts from cracking units
• End-of-pipe emissions from processes such as distillation, cracking and sweetening
• Emissions from fuel combustion in boilers, process heating units, incinerators and engines
• Emissions from flaring of waste gases

With such a range of potential environmental releases, resources need to be targeted carefully. HMIP's last guidance note for oil refinery processes recommended more attention to reduction of particulate emissions from catalytic crackers, and reduction of fugitive emissions of VOCs (HMIP, 1995).

Emission abatement technologies for refineries fall into three generic categories:

• techniques for minimising losses through process redesign or improvement;
• techniques for capturing losses for recycling, energy recovery or controlled disposal;
• techniques for capturing emissions for destruction.

The following paragraphs briefly summarise the emission abatement technologies available.

5.2.1 Control of fugitive emissions

Fugitive losses can sometimes be reduced by using low or zero-loss components such as seal-less pumps; double-sealed flanges; or replacement of flanges by continuously welded piping. Costs are estimated as zero to £100 per tonne VOC abated (hereafter abbreviated as £x/t) for up to 100% abatement efficiency. Regular maintenance programmes can identify and repair or replace leaking components (estimated 44% to 83% efficiency at a cost of £50/t to £100/t).

Vapour losses from tanks may be largely eliminated (99% efficiency) using vapour return systems (£225/t to £1125/t). Floating covers which rise or fall with the level of liquid in the tank can reduce emissions by up to 95% by minimising the headspace volume (UNECE, 1990). Secondary seals may be fitted to minimise evaporative emissions from the space between the tank shell and the floating roof rim. Breathing losses due to changes in ambient temperature can be reduced by painting tanks with a light coloured reflective material. Controls for storage tanks are estimated to be 90% effective at a cost of £100/t to £900/t.

5.2.2 Control of catalyst de-coking emissions

A layer of coke is deposited on catalysts in cracking units, which must subsequently be burnt off to regenerate the catalyst. This releases significant quantities of SO₂, particulates, CO, NO_x, and ammonia. SO₂ may be removed by flue gas desulphurisation, using either a water or lime-based scrubber. For fluidised-bed catalytic cracking, CO can be captured and burnt in a waste heat boiler, and this also converts ammonia emissions to oxides of nitrogen. Particulate emissions may be controlled by cyclones and/or electrostatic precipitators. For moving-bed catalytic cracking, CO is incinerated to negligible levels by passing the flue gases through a process heater fire-box or smoke plume burner and particulates may be controlled by high-efficiency cyclones.

All UK refineries apply some form of abatement to catalytic cracker emissions, although generally this is just a tertiary cyclone to remove particulates. One refinery uses an ESP. Wet scrubbers are not used, partly due to space constraints (it is difficult to retrofit a large scrubbing unit to an existing refinery) and partly because they produce large steam plumes which are difficult to abate. Chemical injection methods for NO_x and SO₂ removal have been investigated but are not generally in use due to their expense (UKPIA, 1998).

SO₂ and NO_x emissions from de-coking are not currently regulated under the large combustion plant directive, although they may be included in forthcoming guidance under the IPPC directive (Wiltshire, 1995).

5.2.3 Control of process plant emissions

Emissions of sulphur compounds, VOCs, CO and particulates arise during processes such as vacuum distillation, catalytic and thermal cracking. Emissions may be vented into blowdown systems or fuel gas systems, or incinerated in flares, furnaces, or waste heat boilers. This generally reduces VOCs by over 99%. Alternative methods of VOC recovery from process vents which may be used in future include pressure swing adsorption, membrane processes or carbon adsorption.

During sweetening of "sour" (sulphurous) gas, hydrogen sulphide (H₂S) is removed by absorption, generally into an amine solution. The H₂S is then converted into elemental sulphur, most commonly via the Claus process which recovers up to 97% of the sulphur deriving from sour gas streams. Tail gas from a Claus sulphur-recovery unit contains a variety of pollutants including SO₂, unreacted H₂S, reduced sulphur compounds and mercaptans (e.g. COS, CS₂). Emission reduction is normally achieved by one of three techniques. Extending the Claus reaction into a lower temperature liquid phase results in overall higher sulphur recoveries (over 99%) with a corresponding reduction in sulphur compound emissions in the tail gas. Tail gas scrubbing (with oxidation or reduction) enables recovery and recycling of sulphur compounds back into the Claus process. Incineration of the tail-gas under proper combustion conditions converts the more hazardous reduced sulphur compounds to SO₂ for release to a stack.

5.2.4 Control of fuel combustion emissions

Combustion exhausts from boilers, process heaters, flares, incinerators and compressor engines are responsible for most of the refinery CO₂ emissions and also produce SO₂, NO_x, particulates, CO, VOCs, polycyclic aromatic hydrocarbons (PAH), and heavy metals (especially where fuel oil is burnt). Emissions can be reduced using similar techniques to those discussed in Section 6 (Fossil fuel combustion), i.e. either by increasing combustion efficiency, controlling combustion conditions, or installing end-of-pipe abatement technologies. Improvements to combustion efficiency will reduce all pollutants (except sometimes NO_x). Combustion modifications can be used to reduce NO_x, CO, VOC, PAH and particulate emissions, and low-NO_x burners are currently being installed at most UK refineries (UKPIA, 1998). End-of-pipe electrostatic precipitators can be used to reduce emissions of particulates and associated heavy metals. The possibility of removal of CO₂ from flue gases has been investigated, but this will remain uneconomic in the short to medium term (see Section 6.4.5).

5.2.5 Control of flaring emissions

Flares routinely burn relatively small volumes of off-gases but potentially may take large volumes during an emergency shut-down. Flaring generally converts hydrocarbon gases to CO₂ and water, with some NO_x. Impurities such as sulphur give rise to emissions of SO₂ and particulates (depending on the gas composition). Incomplete combustion can result in emissions of CO, VOCs and other unburnt hydrocarbons such as PAHs. Control of emissions depends on optimising the combustion conditions. Under good operating conditions over 98% VOC destruction efficiency is possible, with most of the residual VOC in the form of methane. Flare performance can be optimised to over 99% VOC destruction efficiency through the use of steam injection to provide turbulence for efficient mixing and to entrain air for improved combustion; and through good maintenance (£80/t to £400/t for VOC removal).

5.3 CONTROL OF LIQUID AND SOLID WASTES

Wastewater generation at refineries can be segregated into four streams, namely:

• Oily waste stream: Highly contaminated with oil, from process unit floor washings, sampling points, tank drains, blending stations, manifolds, etc.
• Chemical waste streams: e.g. sour water from sulphur recovery units; alkaline/acidic waste streams from regeneration of resin beds in the water demineralisation plant.
• Storm water: Taken from unit and tank areas which may be contaminated with oil.
• Sanitary waste streams: Waste water streams from the refinery toilets and canteen.

Each of these streams are treated at the refinery's effluent treatment plant. Oily waste streams generally have to be pre-treated using an oil-water separator, usually based on a centrifuge, to extract the oil which is disposed of separately. Most treatment methods are based on biological breakdown over extended time periods. Advanced bio-remediation techniques are being developed.

HMIP's last guidance note for oil refinery processes recommended more attention to effluent treatment and to stripping of sour water following sulphur recovery (HMIP, 1995).

5.3.2 Solid waste and sludges

Solid waste from refineries is increasing, due partly to increased environmental requirements which lead to the generation of more residues and sludges from effluent treatment, plus special waste streams such as catalyst waste (CONCAWE, 1995). The cost of disposal in European refineries in 1993 was estimated to be £0.13 per tonne of refinery throughput (ENDS, 1995). Refinery sludges are biologically active, contain heavy metals and may be toxic. The most common methods for disposal of these wastes are presented below.

5.3.2.1 Land Farm for Oily Wastes

Land farming of the oily wastes (including sludge from the waste water treatment (WWT) plant) has been extensively researched and published. The basic concept is to provide approximately 2.5 acres of specially screened soil (with good porosity) about one metre thick over a leachate collection system (coarse gravel) and an impervious membrane (high-density polyethylene). Sludge is evenly applied and the soil is frequently tilled. The hazardous components of the sludge are broken down by the intrinsic biological activity in the WWT sludge, so no additional organisms are necessary, although some additional nutrients may occasionally be necessary (nitrogen and phosphorous fertiliser). Sludges of up to about 10% oil content can be treated without interfering with the biological activity. Stormwater run-on and run-off must be carefully controlled via berms and proper maintenance of surface drainage. Some land farm installations have been in successful use for 30 years and they are the most cost-effective means of disposal for oily sludge.

5.3.2.2 Storage and Disposal of Non-oily Hazardous Wastes

The metal content of these sludges is too high to allow them to be safely disposed on the land and the viscosity is too high to allow them to be land farmed. The alternative is long-term storage in drums in a secure storage facility until the wastes can be safely incinerated or buried in an approved land-fill. Some facilities have upwards of 10⁶ drums safely stored and awaiting future disposal.

5.3.2.3 Groundwater Protection: BETX survey

One of the most effective means of protecting groundwater is to instigate a leak prevention programme involving regular inspection of above-ground piping, flanges and drains for signs of leaks. Monitoring for potential under-ground sources is more involved and is commonly achieved by conducting routine sampling and analysis of groundwater. An analysis for benzene, toluene, xylene and ethyl benzene (BETX) provides a useful way to establish whether motor spirit product has intruded into the groundwater. Total Hydrocarbon analysis is frequently done to establish whether distillate has intruded into groundwater. If hydrocarbons are found, the highest priority is to track them to the source so they can be eliminated. Most likely they will be coming from piping connections to the tankage.

5.4 GASIFICATION OF REFINERY RESIDUES

As mentioned in Section 5.1, technologies to utilise heavy fuel oil and refinery residues at minimum environmental impact may become more important in future, due to the increasing demand for lighter refinery products. Gasification is a particularly promising technology because it can deal successfully with very heavy residues with high sulphur and heavy metal contents, including petroleum coke and asphaltanes. Gasification has been described as "the thinking engineer's combustion". The fuel is heated to a high temperature and pressure, but the supply of oxygen is limited so that combustion does not occur. The product is a gas consisting mainly of carbon monoxide and hydrogen, and impurities can be cleaned from the gas before combustion. This is much easier than cleaning the high volume flue gases after combustion. Sulphur is converted to hydrogen sulphide gas, which can be removed and converted into elemental sulphur. The product gas can be combusted in a combined-cycle gas turbine to raise electricity and steam, and some of the hydrogen can also be separated out for use in other refinery processes, particularly for desulphurisation of oil products (see Sections 6.2.2 and 7.2).

Several refineries overseas are installing gasification technology. In Italy, plants are being installed at Falconara (using dry nitrogen injection to combat NO_x emissions), Priolo on Sicily (using water saturation of the fuel gas to reduce NO_x), and Sarlux on Sardinia, where the input fuel contains 6% sulphur and 1000 ppm Nickel and Vanadium (Aalund, 1997). Other plants are the Pernis plant in the Netherlands (Rhodes 1997a) the Schwarze Pumpe plant near Dresden, which burns waste oils and sludges and generates methanol (Griffiths, 1997) and the Leuna refinery in Germany (Rhodes 1997b).

The possibility of integrating a coal liquefaction plant with a refinery has also been considered (Robinson, 1994). The refinery could make use of the gasification section of the liquefaction plant to dispose of its petcoke and high sulphur residues, and the liquefied coal can be input into the refining process in the same way as crude oil. This technology could become economic in the long term, if the relative prices of coal and oil shift in coal's favour.

6. Fossil fuel combustion for heat and power

6.1 INTRODUCTION

This section deals with the impacts of burning coal, oil and gas⁶ in stationary combustion applications to generate heat or electric power. Fossil fuel use for transport is discussed in Section 7.

The main environmental impacts arise from:

• atmospheric emissions
• disposal of waste ash (for coal and fuel oil)

Atmospheric emissions from fossil fuel combustion are the greatest cause of adverse environmental impacts from energy use both in the UK and globally. They are a major cause of global warming, acid rain and public health problems. Table 2 summarises the emissions arising from combustion of the main fossil fuels in the UK (excluding transport).

Abatement techniques for fossil fuel combustion will be strongly affected by forthcoming tightening of environmental legislation, in particular proposals under the EC acidification strategy for drastically tightening the Large Combustion Plant Directive (LCPD) which sets a ceiling on the total emissions of SO₂ and NO_x from la