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Collaborating Authors
United Kingdom
R.E. Gilliber, J.O. Methven, R. Nicholls Abstract Robust contingency oil spill response arrangements are a prerequisite of nearshore oilfield developments. The Liverpool Bay Development (LBD) represents the greatest UK challenge to date in this regard. This paper describes the development of BHP Petroleum E/R/AIME Region's LBD oil spill response strategy and how it was possible to implement this strategy in a very cost effective way. The strategy was based initially on the field Environmental Impact Assessments, which had identified oil spill hazards and risks based on industry data. Additional studies and tests defined credible oil spill events, specific oil properties and coastal impacts. The types, levels and location of response requirements offshore and onshore were then evaluated - we had our strategy. A series of in-house brain storm sessions reviewed all possible means of achieving the strategy. LBD was unique: a 4 field nearshore development with offshore crude storage and offloading. Novel solutions should be possible, resulting in a more cost effective implementation of the response strategy. Using multi-function vessels was a recurring theme - oil spill response arrangements should not be considered in isolation but together with other marine support services. A crucial step was to realise accepted practices were based on single well or single field scenarios. The company successfully opened a debate within the industry and government agencies on existing UK Regulations governing oil spill recovery, resulting in drafted, more practical Regulations and Guidelines. A shortlist of possible vessel scenarios was then prepared. These were costed and tested against the response strategy by risk analysis, checking double jeopardy cover for all marine support services. Government Agencies were consulted closely. This was particularly important because of the novel nature of the proposals. Their considered and positive responses enabled us to go forward with the most cost effective acceptable solution. Competitive tendering followed and achieved our expectations - robust, cost effective oil spill response arrangements. Introduction BHP Petroleum Ltd, formerly Hamilton Oil Company Ltd, has been operating offshore UK for over 20 years. In this time, the company has achieved a number of "firsts", notably first oil from the UK North Sea in 1975 (Argyll field), and, most recently, first oil from the Liverpool Bay Development in January 1996 marking the start-up of oil production off Britain's West Coast. This 1.2 billion development involves oil and gas production from four fields (Hamilton, Hamilton North, Lennox and Douglas). Oil is exported via a 17km subsea pipeline to a CALRAM moored 870,000 bbl capacity oil storage installation (OSI), from which the oil is transferred to export tankers. Gas is transported via a 20" subsea pipeline to an onshore receiving and processing terminal in North Wales. It is the first integrated development in nearshore UK waters involving the production and export of both oil and gas. In total there are 7 fixed offshore installations all within 20 miles of land, with one (the Lennox platform) only 5 miles from shore. P. 129
- North America > United States (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
Abstract Preventing the occurrence of accidents in drilling and well servicing operations is a constant and major concern for any company or contractor acting in the upstream business. Analysis of accidents often identifies a number of contributing factors and/or anomalies, among which the equipment related items play a significant role. This article concentrates on the rig inspection process as a consistent method of detecting equipment related anomalies before operations commence. These inspections enable the necessary corrections to be made in due time, thereby limiting the occurrence of accidents once the rig is in operation. When in-depth and systematic rig inspections are carried out, it is that the percentage of accidents where equipment failure is the major cause remains very low. However, equipment condition factors contributing to the accidents still remain present in a large number of cases. Introduction Rig Inspection activities are normally an important part of the drilling safety programme. The inspection objective is both to prevent the occurrence of accidents, to limit their consequences and to minimise non-productive time linked to equipment failure. Analysis of the accidents occurring during rig operations indicates that equipment is often involved as a contributory factor. As rig equipment maintenance standards have, in general, suffered from depressed rig rates during the past ten years, the need for detailed inspection has become more important. Rig inspections normally consist of an independent and thorough survey of the rig drilling, mechanical, electrical, well control, marine and safety equipment. This allows specialised expertise to be targeted at the equipment maintenance standards, including full testing of equipment safety devices, to determine the level of equipment maintenance and safe working condition. The objective of this paper is to present the conclusions and lessons learnt from these inspections, based on the survey of 75 rigs carried out since 1991. This paper also demonstrates the benefits of this integrated philosophy, which includes a better safety approach, a worldwide standard, the rapid inclusion and verification of relevant safety bulletins and alerts, plus appropriate examples of the system achievements, and confirms the old saying that "a poorly maintained rig can never be a truly safe rig". 3. FACTORS AFFECTING SAFETY IN RIG OPERATIONS It is important to establish the added value of inspection among the actions taken by Contractors/Companies to improve rig operations with respect to safety results. In this search for improvement, one of the necessary steps is to organise a consistent incident reporting and analysis system during rig operations. This system should apply not only to accidents and near-misses, but also to anomalies, i.e. unsafe acts, unsafe equipment and incomplete procedures which can be seen by the rig personnel as contributing factors to the occurrence of accidents. For deep analysis of incidents, methods such as the Cause Tree Analysis can be used. This investigation method enables accurate identification of the contributing factors to the accidents, and those which need to be corrected to prevent accident reoccurrence. A survey of over 41 LTA's occurring over one year of drilling activity indicates that the contributing factors leading to accidents can be split into three main groups: Group 1: Human Behaviour Factors. These factors typically cover the human qualities necessary to minimise the occurrence of and exposure to accidents during rig operations. They are always present and generally constitute the major cause of accidents. These factors can be minimised by a comprehensive safety programme, including the set up of clear corporate objectives, proper management of human resources, safety incentives, safety training, etc. If properly organised, this safety programme promotes the detection of anomalies on the rig site which will fuel further improvements. By nature, these factors are more subjective than objective; they are highly dependant on the area environment (such as safety culture), and improving them generally requires significant time and effort. P. 871
- Health, Safety, Environment & Sustainability > Safety > Safety risk management (1.00)
- Health, Safety, Environment & Sustainability > HSSE & Social Responsibility Management > HSSE management systems (1.00)
- Health, Safety, Environment & Sustainability > HSSE & Social Responsibility Management > HSSE reporting (0.88)
Abstract The oil company operates North Sea Oil Production Platforms which have several subsea developments connected by subsea pipelines. A specialist research institute was contracted by the company to obtain reference crude oil fingerprints for each subsea oil pipeline and store this information in a specially constructed computer database and fingerprint matching system. Both crews from the platform's stand-by vessels were then trained in the correct procedures for sampling small slicks at sea, with laboratory validation of samples collected during the training exercise. Subsequently, during two incidents of leaking subsea pipelines, oil spill samples were taken by stand-by vessel crews. Analysis of the samples onshore, followed by computer comparison of their fingerprints to those of the reference oils in the database, allowed early identification of the leaking pipeline prior to confirmation by ROV inspection. Oil spill fingerprinting proved a highly cost effective tool, ensuring optimum use of expensive DSV/ROV mobilisation and use. It also permitted pipelines not implicated in the leak to be rapidly put back into operation. Introduction Significant advances in the use of chemical analysis to identify the source of oil spills have been made over the last two decades, particularly in the application of methods based on gas chromatography-mass spectrometry (GC-MS). These were originally developed for geochemical, oil exploration purposes. However, their potential for identifying the sources of oil spills, particularly from shipping, was soon recognised and exploited. More recently, these techniques have also been successfully used to help oil companies find the sources of subsea leaks from offshore pipelines. Crude oils contain a complex mixture of organic compounds, of which a majority are hydrocarbons. The remainder consists of oxygen-, nitrogen- and sulphur-containing compounds, as well as organo-metallic compounds containing nickel, vanadium, iron, copper etc. Although superficially similar, the chemical composition of oils varies according to the nature (and geochemical history) of the organic matter from which they are derived. GC-MS is used to study the distribution of 'biological marker' compounds, in particular the steroidal and triterpenoidal alkanes (steranes and triterpanes) which are present in a complex assemblage in crude oils. Although the concentrations of these compounds are low, using OC-MS it is possible to study their distribution, variations of which form the basis of the mass spectrometric fingerprinting technique. Whereas biomarker distributions can be significantly different between oilfields from different geographical areas the fingerprints of crudes from the same geographical area tend to be very similar. In these circumstances the use of computerised fingerprint comparison software has proved extremely valuable for differentiating these oils. P. 811
- North America > United States (0.94)
- Europe > United Kingdom > North Sea > Northern North Sea (0.29)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.31)
- Europe > United Kingdom > North Sea > Northern North Sea > West-Central Viking Graben > Block 9/13 > Ness Field > Lewis III/IV Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > West-Central Viking Graben > Block 9/13 > Ness Field > Heather Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > West-Central Viking Graben > Block 9/13 > Ness Field > Beryl Formation (0.99)
- (10 more...)
Abstract Ranking of environmental projects in relation to other projects in a company's portfolio of business has posed problems for years. Substantial effort has been spent toward developing systems or methodologies to overcome this problem but have been met with limited success. To be accepted as a responsible industry and manage the environmental discharge issue, the oil industry should through a process of continuous improvement minimise effluents and discharges that are known to harm the environment. Many oil companies have already made substantial headway in reducing discharges through low cost operational changes and better awareness. However these are often not enough and environmental projects requiring capital investments are needed. These projects will normally proceed when regulatory driven, but they have more difficulty proceeding if they are not regulatory driven and must rely on meeting the economic criteria applicable for approval. So how is a company to decide which environmental projects to do? In the absence of legislation, it is evident that, as more involved and expensive options are required to achieve this goal, the need for a method to rank environmental expenditures for the industry is necessary. In addition, the concept of basing the decision solely on the environmental effects and economics of a discharge must be expanded. Other considerations which drive the industry towards improved environmental performance such as public perception must be considered. This paper outlines a methodology that allows for the ranking of environmental proposals at a company level taking into account factors such as public perception and possible future legislation and enables the use of the 80/20 rule. The methodology has been applied by Shell U.K. Exploration and Production, operator in the U.K. sector of the North Sea for Shell and Esso, and is applicable to most industries. Introduction In many countries the oil industry is forced to accept the Government's approach of prescriptive regulation of environmental discharges (e.g. United States). Here the regulators set the specific discharge standards for each waste stream. In the UK there is a mix of prescriptive legislation and goal setting being applied. In other countries (e.g. The Netherlands) a National Environmental Policy Plan, NEPP, has been passed which sets levels, for waste streams. To achieve these levels, the industry sector and the government both agree on a covenant to achieve longer term environmental discharge reductions. This covenant approach or the prescriptive approach both make a company's decision for them on where to spend their environmental money but in fact may provide a small benefit for the environment at a high cost. If companies were empowered to reduce emissions and with their knowledge of the process, they could allocate their expenditures better and thereby provide a much higher environmental benefit. In addition to compliance and efficient spending of the environmental funds, the oil industry must be able to assure investors that they are handling the environmental risk in a financially constructive way. Short term approaches are not considered acceptable. Operators must be seen to be improving their environmental performance just like their safety and financial performance. Excessive discharges or contributions to long term environmental liabilities are viewed as poor company management. Management of the environment by industry is becoming increasingly a public concern. Environmental external reporting is becoming more prevalent to meet this concern. A methodology which achieves this helps to lend credibility to the effort. In addition a company (or industry) which is proactive towards the environment is one that may avoid prescriptive legislation and possible future criminal or financial liabilities. Therefore a methodology must be in place in order to efficiently achieve these needs. The Environmental Target Setting and Ranking (ETSAR) methodology achieves this and embraces these goal setting approaches by setting objectives often beyond the legal requirements. P. 567
- North America > United States (0.88)
- Europe > United Kingdom > North Sea (0.25)
- Europe > Norway > North Sea (0.25)
- (2 more...)
- Law (1.00)
- Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Israel > Mediterranean Sea > Southern Levant Basin > Or Field (0.99)
- North America > United States > Arkansas > Paris Field (0.89)
- Europe > United Kingdom > North Sea (0.89)
- (3 more...)
Environmental Risk Management of Produced Water - A Demonstration of the CHARM Model Used for the Ula Field in the North Sea
Bakke, S. (Aquateam - Norwegian Water Technology Centre A/S) | Ofjord, G.D. (Aquateam - Norwegian Water Technology Centre A/S) | Vik, E.A. (Aquateam - Norwegian Water Technology Centre A/S) | Sande, A. (BP Norge Ltd.)
Abstract This paper gives a demonstration of environmental risk analysis and risk management by use of the CHARM (Chemical Hazard Assessment and Risk Management) model for making cost/environmental benefit evaluations of produced water handling. The BP operated Ula field in the North Sea is used as a demonstration case. The CHARM model is developed by Aquateam, Norway and TNO in the Netherlands on behalf of the oil operators, chemical suppliers, and environmental authorities in the North Sea countries. The CHARM model has been discussed and is accepted by the Oslo and Paris Commission (OSPAR). The environmental risk analysis demonstrated in this paper covers evaluation of the environmental impact of the produced water discharges, including chemicals and natural constituents from the Ula platform. The environmental risk analysis was performed for various environmental management options. Two options were elaborated for comparison to a reference situation. The Ula produced water constituents demonstrated variable contributions to the total environmental risk. The environmental risk was slightly reduced by improved water treatment, but the most significant reduction was seen for the option of produced water reinjection (PWRI). PWRI reduced the produced water discharges with 90%, indicating that the environmental benefit was superior. PWRI was also able to compete economically with the other options. It should be noticed that the PWRI option did not reduce the production capacity at Ula. If so, the economic situation would have been significantly different. Introduction The produced water discharges to the North Sea are steadily increasing as the oil producing fields are becoming more mature. The discharges were 187 million m3 in 1993 and are expected to culminate at a level of 340 million m3 in 19971. As the oilfields mature, the produced water volumes will increase, more chemicals will be used, and hence, the environmental risks related to produced water discharges will increase. The environmental risk can be reduced by choosing less harmful chemicals, improving the water treatment, reinjecting the produced water or selecting alternative (e.g. corrosion resistant) materials. These choices are, however, not always clear cut. Which option is the better for the environment and to which cost? The optimum choice will, however, be site specific. Traditionally, risk is a product of consequences and probability. The use of risk analysis within safety management has been applied for a long time. This method has recently also been introduced in the environmental field for evaluation of environmental risk of acute incidents in Norway. In the offshore industry, environmental risk analysis is normally associated with accidental oil spills. The environmental risk discussed in this paper is, however, related to continuous discharges of produced water and includes the combined risk of residual chemicals and oil as well as natural organic and inorganic constituents in the produced water. P. 473
- Europe > United Kingdom > North Sea (1.00)
- Europe > Netherlands > North Sea (1.00)
- Europe > Denmark > North Sea (1.00)
- Europe > Norway > North Sea > Central North Sea (0.61)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Water & Waste Management > Water Management > Lifecycle > Discharge (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019 > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > King Lear Area > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > United Kingdom > England > Hampshire Basin > PL 089 > Block 98/6 > Wytch Farm Field > Sherwood Formation (0.98)
- (7 more...)
The Effect Of Ventilation And Gas Cloud Sizes On Explosion Overpressures
Moros, A. (BP Exploration Operating Co. Ltd.) | Tam, V. (BP Exploration Operating Co. Ltd.) | Webb, S. (BP Exploration Operating Co. Ltd.) | Paterson, K. (BP Exploration Operating Co. Ltd.) | Coulter, C. (BP Exploration Operating Co. Ltd.)
Abstract Gas cloud build up from releases in offshore process modules which could eventually lead to an explosion depends on the air flow in the module and the equipment arrangement. In any offshore operation it is also necessary to estimate the frequency of gas cloud sizes in a module. These in turn affect the explosion frequency which ultimately has an impact on the Individual Risk (IRPA) and Temporary Refuge Impairment Frequency (TRIF). In this paper we describe the overall methodology of how to estimate a gas cloud frequency from a specified release and the models available for predicting ventilation and gas dispersion in offshore operations. Introduction Within the process modules of an Oil/Gas production site, gas cloud built up resulting from a release, and which could eventually lead to an explosion, depends on the flow through the modules and the ventilation rates. In any offshore operation it is also necessary to estimate the frequency of gas cloud sizes in a module, which in turn affect the explosion frequency and ultimately has an impact on the Individual Risk (IRPA) and Temporary Refuge Impairment Frequency (TRIF). This is clearly linked to the gas cloud size in the process modules. In this paper we will describe the methodologies used in BP for estimating the maximum achievable gas cloud in a module from a number of credible releases in different wind and ventilation conditions. In addition we will describe the procedure for estimating the probabilities of explosions to exceed a specified threshold and the models used in these procedures. The applicability of the methodology will be demonstrated through two case studies, PROCESS AREA VENTILATION AND GAS ACCUMULATION The flows and the ventilation rates in a module vary according to the position of the module in the platform/rig relative to the ambient wind, geometrical layout of the module and whether it is open or closed (i.e. having louvers, wind walls, etc.). The role of the ventilation concept used traditionally in industry has two major functions:To assist in removal of heat generated by the process system and To diffuse and remove leakages of hydrocarbons from process equipment. The concept of ventilation rates could be misleading when used in conjunction with gas cloud dilution. In a large module (i.e. 3000 m3 volume), small releases will not affect the flow in the module and therefore the flow generated from the ambient conditions (which the ventilation rates are based on), will be responsible for the dilution of the released gas. In contrast, large releases (say >10 kg/s) in the same module, will generate their own flow which will disrupt/modify any internal flow generated from the ambient wind. In such a scenario, the use of ventilation rate has very little meaning. P. 399
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/24a > Foinaven Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/19 > Foinaven Field (0.99)
Abstract Mercury is known to be present as a trace-gas in the Rotliegend natural gas reservoirs. In the gas reservoirs under consideration levels of between 0.3 – 0.5 mg/Nm3 are found. During the gas treatment process the mercury is removed together with water and higher hydrocarbons. All waste streams, for example sludge, which are accumulated in gas treatment units and equipment e.g. glycol- and coalescence filters and heat exchangers are contaminated with mercury. In the past this mercury contaminated waste has been disposed of at special dump sites such as in depleted salt mines in Germany. In order to reduce the impact on the environment, NAM decided to develop an alternative method of disposal. From a feasibility study it was concluded that proper conditioning of the waste streams followed by a thermal oxidation process would be the best option to clean mercury contaminated waste. As there was no suitable thermal treatment process available, an in-house research laboratory was approached. Their investigation resulted in a "High-Temperature-Oxidation (HTO)" process. On this basis NAM decided to build a facility where all its mercury contaminated waste could be treated. It consists of two separate processes; i.e. the pretreatment and volume reduction facility and the final treatment using the HTO - process. This paper gives an overview of the required pre-treatment facilities, describes the HTO-process and summarises the achieved treatment results. Introduction Produced natural gas especially from Rotliegend reservoirs contains small quantities of gaseous elemental mercury. When applying the low temperature separation technique to bring the gas to sales specification the mercury is also condensed in the metallic form. A process flow scheme of the applied separation technique is shown in figure 1a/b. The majority of mercury may be directly extracted. However, a small proportion of this metal enters the liquid treatment facilities and inevitably leads to the contamination of equipment and waste streams. The resulting materials to be treated can be divided into two broad subgroups, i.e. disposable and non-disposable items. The disposable items comprise of sludge, coalescence-filters, glycol-filters, scrap material, spent activated carbon and occasionally soil. The non-disposable items are equipment such as heat exchangers, personal protection items and trucks used to transport water and condensate. Until now the waste has been collected centrally in a very basic facility at a production site within the field and prepared for export and storage in a depleted former salt mine in Germany. In 1989 a re-appraisal of the situation, in the light of improving standards for environmental care and personal exposure called for the design of a new facility. The Netherlands has directed in its National Environmental Policy that the amount of hazardous waste must be reduced and that the export of hazardous waste with the objective of dumping is no longer accepted. In line with this policy the export of hazardous waste has officially been stopped by the authorities since January 1996. This national policy is in line with the NAM policy, i.e. to reduce the impact on the environment as much as possible. In the following sections an overview of the development is given, resulting in a two stage treatment process for all mercury contaminated waste. P. 269
- Europe > Netherlands (0.49)
- Europe > Germany (0.44)
- Europe > United Kingdom > North Sea > Southern North Sea (0.24)
- Water & Waste Management (1.00)
- Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > Netherlands > Groningen > Southern North Sea - Anglo Dutch Basin > Groningen License > Groningen Field > Upper Rotliegend Formation (0.99)
- Europe > Netherlands > Groningen > Southern North Sea - Anglo Dutch Basin > Groningen License > Groningen Field > Limburg Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Rotliegend Sandstone Formation (0.98)
- (2 more...)
Factors Affecting Methods for Biodegradation Testing of Drilling Fluids for Marine Discharge
Vik, E.A. (Aquateam - Norwegian Water Technology Centre A/S) | Nesgard, B.S. (Aquateam - Norwegian Water Technology Centre A/S) | Berg, J.D. (Aquateam - Norwegian Water Technology Centre A/S) | Dempsey, S.M. (Aquateam - Norwegian Water Technology Centre A/S) | Johnson, D.R. (Conoco Norway Inc.) | Gawel, L. (Conoco Ponca City, U.S.A.) | Dalland, E. (OLF/Statoil Norway)
Present address: This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at the SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Write Librarian, SPE, P.O. Box 833836, Richardson, Texas 75083-3836, U.S.A., fax 01-214-952-9435. Abstract Although general agreement was reached between the OSPARCOM (Oslo and Paris Commission) countries in 1994 regarding testing of drilling chemicals for approval for use and discharge, there are still some practical variations concerning the implementation. In all standard environmental compliance areas, such as toxicity, bioaccumulation and biodegradability, there has been, or is, some concern about the reassessment of change. It is only recently that an agreement has been reached on test species for toxicity assessment of drilling fluids and chemicals for North Sea discharge. Regarding approval for the use of synthetic based muds (SBMs), biodegradability has probably been the most controversial issue with respect to the test methods, test results, acceptable degradation rates and overall environmental impact. Drilling fluids used in SBMs have low water solubilities and are adsorbed onto drill cuttings. They are known to enter the marine sediments and will, in high concentrations, and when they are buried under a layer of cuttings or under sediments, accumulate in anoxic marine sediments. OPSAR has therefore required that both aerobic and anaerobic biodegradation test results be available for the base fluids of SBMs. Presently, a seawater biodegradation test protocol has been developed into an OECD Guideline for water soluble materials, but no standard test protocol has been agreed upon for poorly or non-water soluble materials. This is the case both for aerobic or anaerobic biodegradation tests. For the aerobic biodegradation test, several attempts have been made to come up with a standard seawater test, but presently different laboratories use different protocols. Small differences in existing test protocols for aerobic seawater tests have resulted in great variations in test results obtained between different test laboratories. For the anaerobic test, only a few attempts have been made to come up with a seawater test protocol and only a limited number of test results exist. It has been the general opinion among North Sea environmental authorities that rapid degradation will minimize the environmental impact, thus allowing fast recovery of the seabed. This argument was introduced at an early stage and lead to the development of a set of seabed simulation studies. The results of these studies generated alternative viewpoints. One argument was that aerobic degradation in a localized area will lead to anoxic conditions which immediately can have a lethal impact on the benthic fauna. Another argument was that although the base material may be relatively non-toxic, the by-products or any other constituents of the drilling mud, may be toxic. The ultimate issue concerning the use of any drilling fluid should therefore be environmental impact rather than fate. P. 697
- Europe > United Kingdom > North Sea (0.46)
- Europe > Norway > North Sea (0.46)
- Europe > Netherlands > North Sea (0.46)
- (3 more...)
The Impact of CO2 Taxation on Oil and Gas Production in Norway. Abstract This paper analyses the effect of the CO2 tax which was imposed on the burning of gas in the Norwegian sector of the North Sea, effective in 1991. The introduction of the tax resulted in a number of technical improvements aimed at the reduction of flaring, and increased energy efficiency of the power generation and total production process. An economic analysis was done to establish the following:How did the tax affect the profitability of the technical measures which were implemented - did the tax make it profitable, or would it have been profitable without the tax; can we expect improvements to continue in the coming years; and what will be the impact on the development of new fields, on field abandonment and on measures to improve oil recovery - how much more oil will be left in the reservoir because of the tax. The first task was analysed by an empirical approach, the latter based on models. The reduction in CO2 discharge during 1990-1993 was in the order of 8%, the main contribution came from reduction in flaring. This rate of improvement is not expected to continue, since most processes have been brought up to "state-of-the-art" by during these initial years. However, continuous energy optimisation is still expected to give some improvements. The majority of the technical measures taken to reduce the CO2 discharge proved to be profitable without the tax, and no unprofitable measures were implemented. The effect of earlier abandonment of fields is smaller than expected, advancing the abandonment by a few weeks for a typical North Sea field. The same seems to be the case for development of new fields. The additional reserves needed to compensate for the tax is in the order of 3 – 4% for a medium GOR oil field, above 5% for a larger gas field. Introduction In January 1991, the Norwegian authorities introduced a CO2-tax, which was originally set at 0.6 NOK/Sm3 of gas which was flared or used for energy purposes. and 0.6 NOK per liter of diesel fuel. The tax has gradually been increased, to reach 0.82 NOK/Sm3 in 1994. This is equivalent to short of USD 20 per barrel of oil, if we compare by energy content, and is the highest CO2-tax in the world. The rationale behind a tax is to add a cost for the use of the environment which is otherwise not reflected in the price/cost structure of the production. This added cost is expected to make the industry take alternative technology or revised procedures into use, and by that reduce the CO2 emission, and reduce the tax. To make such policy work, alternative technology must exist. or be developed. CO2 emissions from the petroleum industry represents more than 20% of the total emissions in Norway. A projected increase in the emissions due to increased oil and gas extraction will make it difficult to stabilize emissions at 1989 level by the year 2000, which has been the Norwegian government's stated objective. Gas consumption for energy use to extract and transport oil and gas contribute 83% to the emissions, and flaring gas contributes 10%. The remainder is diesel consumption on exploration rigs, and well testing. In principle, the CO2 tax may have three different effects for the oil and gas sector, of which all could contribute to reduced emissions:–The tax may lead to fuel substitution away from carbon intensive fuels; –The tax will spur investments in more effective technology and more energy efficient operational procedures; –The tax may contribute to reduced extraction of oil and gas, since taxation increases the extraction cost and thus reduces the profitability of the production. P. 573
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > Norway Government (0.54)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Statfjord Group (0.94)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Cook Formation (0.94)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Brent Group (0.94)
- (17 more...)
Abstract There are approximately 70 working and planned structures in the Norwegian sector of the North Sea. The majority are steel-legged installations (oil and gas jackets) placed in depths ranging from 70 to 200 m. Several oil fields and structures are soon to be abandoned. Production from the North-east Frigg and Odin fields, was stopped in 1993 and 1994 respectively From a technical and safety viewpoint, most of the structures are probably removable. Economically, concern has been expressed as to whether it is necessary to remove to shore all the installations. A positive environmental impact may be achieved by using some of the structures as fish aggregating devices. The implications of creating an artificial reef from a steel jacket by toppling in-place are discussed. A typical steel jacket in the Norwegian sector of the North Sea weighs 5,000 - 10,000 tonnes (excluding piles) and has a volume of 100,000-150,000 m3. It may also be possible to utilise some of the deck modules. Technical and biological aspects relating to artificial reef establishment are reviewed, including the identification of the chemicals and materials that need to be removed prior to toppling. Suggestions for further management and monitoring for documentation purposes, are reviewed. A 5 year monitoring programme protocol is proposed. The creation of a test reef from a steel jacket would present an ideal opportunity to obtain essential data, hitherto lacking in the North Sea, on the usefulness of high profile steel reefs as fisheries management tools. Data obtained would also be used to propose effective North Sea reef management and exploitation strategies. The suitability of using material arising from the petroleum industry, as components for artificial reefs, seeks to be determined. Introduction There is a growing concern regarding the fate of oil and gas facilities that are abandoned as a result of declining production in some fields. Traditionally, the total removal of all abandoned offshore oil and gas related structures has been the only acceptable disposal strategy. Different abandonment options have though been proposed for consideration in recent years. It is technically possible to remove most of the structures placed on the Norwegian continental shelf, but in some instances there may be safety risks, both to the people performing the removal and to the environment in the area. It is then, for safety and economic reasons, unlikely that the total removal of all structures in the Norwegian sector will prove a feasible disposal option. The potential impacts, both positive and negative, of leaving the structures in the sea should therefore be addressed. There is no doubt that offshore structures act as fish attracting devices, and thereby act as artificial reefs. The Japanese have a large industry centered around the construction of artificial reefs to attract fish and to increase the biological productivity in the ocean. P. 295
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > PL 030 > Block 30/10 > Odin Field > Hermod Formation (0.98)
- (6 more...)