North Sea Platform Research Articles

Application of Hierarchical Analyst Domino Evaluation System (HADES) in offshore oil and gas facilities' decommissioning: A case study

Offshore facilities need to be decommissioned after completing their design lives. Quantity Risk Assessment (QRA) is usually compulsorily required in the offshore industry, but the current QRA technology for decommissioning projects still has some gaps that need to be filled. Most current QRA technologies can only be used for static risk assessment before the project starts, which may underestimate the risk involved in decommissioning operations. Therefore, sophisticated stationery and dynamic QRA techniques must be developed for offshore decommissioning projects. This paper proposes the Hierarchical Analyst Domino Evaluation System (HADES) for decommissioning, and it considers domino effect accidents (DEAs). Integrating the Analytic Hierarchy Process (AHP) into QRA, multiple layers of domino accident analysis are carried out for each decommissioning procedure by taking the two triggering mechanisms of domino effect accidents as the core for obtaining more accurate QRA results. Furthermore, designing a causality matrix to classify and stratify identified hazards. Correspondingly, the targets criteria database established for judging triggering situations is also ground-breaking. To demonstrate the advantages of HADES, a decommissioning project in the North Sea platform North West Hutton is employed as the case study to analyze the risk in decommissioning procedures and identify the hazards in each process. These hazards are classified and stratified into one primary layer and several domino layers for further assessment. The risk assessment results are very close to those published, proving the HADES system's feasibility.

Advanced exergy analysis of the oil and gas processing plant on an offshore platform: A thermodynamic cycle approach

Ambitious targets on reduction of greenhouse-gas emissions have motivated further studies to improve energy efficiency in offshore gas and oil production. Identifying the causes of inefficiencies and the improvement potentials within these processes is crucial. The oil and gas processing plant on a North Sea platform is evaluated by advanced exergy analysis for a real production day. The study focuses on components and sub-systems with high exergy destruction through conventional exergy analysis in previous research. Splitting the exergy destruction into endogenous and exogenous parts provides information about mutual interdependencies among the system components. The results show that the inefficiencies of compressors are attributed to their inherent irreversibility, while the exergy destruction within the coolers could particularly be reduced by improving the remaining system components. Further, the total exergy destruction avoidable by improving each single component determines the importance of the components. The results indicate that the compressors have relatively large exergy saving potential (14% of total power consumption), while it is relatively low for coolers. Advanced exergy analysis suggests an optimization sequence different from the conventional exergy analysis. The findings indicate that the improvement efforts should be focused essentially on the compressors, especially for the recompression compressors with anti-surge operations.

Monitoring the Gas Turbine Start-Up Phase on a Platform Using a Hierarchical Model Based on Multi-Layer Perceptron Networks

Abstract Very often, the operation of diagnostic systems is related to the evaluation of process functionality, where the diagnostics is carried out using reference models prepared on the basis of the process description in the nominal state. The main goal of the work is to develop a hierarchical gas turbine reference model for the estimation of start-up parameters based on multi-layer perceptron neural networks. A functional decomposition of the gas turbine start-up process was proposed, enabling a modular analysis of selected parameters of the process. Real data sets obtained from observations of the turbo-generator set located on a North Sea platform were used.

Paleozoic basin reactivation and inversion of the underexplored Northern North Sea platforms: a cross-border approach

Abstract Well penetrations on the UK East Shetland Platform (ESP) prove 1–8 km-thick Devonian post-orogenic extensional collapse-related successions. Conversely, extremely thick (1–6 km) Permo-Triassic basin-fills without Devono-Carboniferous units were in the past interpreted west of the Utsira High, on the Norwegian Horda Platform and Stord Basin, albeit Pre-Triassic well penetrations are here very rare. In this work, the nature and age of Paleozoic–Triassic strata and structures in these underexplored platform regions are tentatively constrained by performing cross-border regional seismic interpretations east and west of the Viking Graben. We highlight cross-border analogies in structural style and seismic facies, with a similar evolution dominated by polyphase inversion tectonics and structural grain preservation. In the Norwegian study areas, much of the half-graben sedimentary fills may be interpreted as Devonian–?Carboniferous in age as in the ESP, rather than overly thick Permo-Triassic successions. Major graben-bounding extensional faults are low angle ( c. 25°–33°), approximately north-striking and are likely to be rooting downwards into reactivated Caledonian shear zones. Rifting development occurred in multiple episodes, possibly creating different traps. Prior to Permian–Jurassic rifting, many low-angle Caledonian thrusts were subject to extensional inversion in the Devonian and then to Variscan compressional reactivation, causing vertical extrusion and deformation of Devonian synrift wedges.

Advanced Exergy Analysis of the Oil and Gas Processing Plant on a North Sea Platform: A Thermodynamic Cycle Approach

Advanced Exergy Analysis of the Oil and Gas Processing Plant on a North Sea Platform: A Thermodynamic Cycle Approach

Dynamic simulation of offshore gas processing plant for normal and abnormal operations

Offshore oil and gas production is contributing to almost 30% of the total global oil and gas production. Since access to the offshore facilities is difficult, there is interest in monitoring the production facilities remotely. Multivariate statistical methods can be effectively used to monitor the offshore gas production plant. In this research work, monitoring of an offshore production plant is described. To demonstrate the monitoring cycle, a benchmark model for the offshore facilities is required. Mathematical modeling and simulations are useful tools for designing and predicting the accurate behavior of a production plant. As the first phase, we simulate an offshore oil and gas production plant using the process modeling tool, Aspen HYSYS. The model is based on the process specifications of a gas processing plant at the North Sea platform reported by Voldsund et al. (2013). Several common faults from different fault categories, such as actuator faults and disturbances, are introduced and simulated in the dynamic system. A total of seven dynamic scenarios are investigated, and their impacts on the overall hydrocarbon production are analyzed. According to the results, the dynamic simulation can accurately generate the system response, including responses during faulty conditions. The simulations files, normal, and abnormal data are made available electronically. The developed model can be used as a benchmark system to test monitoring algorithms for offshore production facilities. In the second phase, we will describe the monitoring scheme for the plant.

Thermo-Economic Modelling and Process Integration of CO2-Mitigation Options on Oil and Gas Platforms

The offshore extraction of oil and gas is an energy-intensive process associated with large CO2 and CH4 emissions to the atmosphere and chemicals to the sea. The taxation of these emissions has encouraged the development of more energy-efficient and environmental-friendly solutions, of which three are assessed in this paper. The integration of steam bottoming cycles on the gas turbines or of lowtemperature power cycles on the export gas compression can result either in an additional power output, or in a greater export of natural gas. Another possibility is to implement a CO2-capture unit, which allows recovering CO2 that can be used for enhanced oil recovery. In this paper, a North Sea platform is considered as case study, and the site-scale retrofit integration of these three options is analysed, considering thermodynamic, economic and environmental performance indicators. The results illustrate the benefits of valorising the waste heat recovered from the exhaust gases, as the total CO2-emissions can be reduced by more than 15 %. Exploiting low-temperature heat seems feasible, although more challenging in retrofit situations. Integrating CO2-capture appears promising with a CO2-avoidance cost between 23 and 29 $/tCO2 for the chosen economic assumptions.

The Alexander L. Kielland Disaster Revisited: A Review by an Experienced Welding Engineer of the Catastrophic North Sea Platform Collapse

The objective of this review regarding the catastrophic failure of an important welded structure, the Alexander L. Kielland platform, was to indicate that the investigation team should have comprised and involved an experienced welding engineer. Lack of involvement of the welding engineer can lead to misinterpretation of the evidence which results in the incorrect identification of the cause of failure. In this case, the Alexander L. Kielland platform, only the mechanism of failure, which was by fatigue, was correctly identified by the investigation team, this review by the author has correctly identified the true causes that lead to catastrophic failure. Derived from identification of the true causes, i.e. a need for more appropriate design criteria and suitable welding protocols, then by the rectification of these causes, we can suppress the vulnerability of the structure to these modes of fatigue failure operating. The result of this review should therefore be welcomed by anyone concerned with design, construction and the health and safety of operation of these types of welded structure.

Biodegradation in seawater of PAH and alkylphenols from produced water of a North Sea platform

Operational planned discharges of produced water (PW) to the marine environment from offshore oil production installations, contain low concentrations of dispersed oil compounds, like polycyclic aromatic hydrocarbons (PAHs) and alkylated phenols (APs). Biotransformation in natural seawater (SW) of naphthalenes/PAHs and phenol/APs in field-collected PW from a North Sea platform was investigated in this biodegradation study. The PW was diluted in SW from a Norwegian fjord, and the biodegradation study was performed in slowly rotating carousels at 13 °C over a period of 62 days. Naphthalenes/PAHs and phenol/APs biotransformation was determined by first-order rate kinetics, after normalization against the recalcitrant biomarker 17α(H),21β(H)-Hopane. The results from this study showed total biotransformation half-lives ranging from 10 to 19 days for groups of naphthalenes and PAHs, while half-lives for APs (C0- to C9-alkylated) were 10–14 days. Biotransformation half-lives of single compounds ranged from 8 to >100 days for naphthalenes and PAHs (median 16 days), and from 5 to 70 days (median 15 days) for phenols and APs. Four of the tested PAHs (chrysene, benzo(b)fluoranthene, benzo(e)pyrene, benzo(g,h,i)perylene) and one AP (4-tert-butylphenol) showed biotransformation half-lives >50 days. This is one of a few studies that has investigated the potential for biodegradation of PW in natural SW. Methods and data from this study may be used as a part of Risk Based Approaches (RBA) for assessments of environmental fate of PW released to the marine environment and as part of the persistence related to risk.

Revisiting the Estimate of the North Sea Air‐Sea Flux of CO2 in 2001/2002: The Dominant Role of Different Wind Data Products

AbstractFor the North Sea, a semienclosed shelf sea in the northeastern North Atlantic, the seasonal and annual CO2 air‐sea fluxes (ASF) had been estimated for 2001 and 2002 in earlier work. The underlying observations, ΔpCO2, salinity, and temperature had been combined with 6‐hourly wind data derived from ERA40 reanalysis. In order to assess the impact of different wind data products on the computation of CO2 ASF, we compared ERA40 wind data with coastDat data derived from the nonhydrostatic regional climate model COSMO‐CLM. From the four observational months September, November, February, and May all but the May data show higher wind speeds for coastDat than for ERA40, especially off the Norwegian, UK, and continental coasts. Largest differences occur in the northern offshore areas. The comparison with observed wind data supports this feature generally: At Helgoland, an island in the German Bight, and at the Belgium pile “Westhinder” the ERA40 data underestimate both, the coastDat data and the observations. Wind observations for two Norwegian North Sea platforms were available: At the northern station “Troll” off the Norwegian coast the coastDat data overestimate the observations in winter. At “Ekofisk” in the central North Sea the ERA40 data fit the observations well, while the coastDat data slightly overestimate the observational data in all months but in May. The corresponding CO2 ASF estimates show strongest deviations off the Norwegian coast. Using different bulk formulas for determining the net annual ASF resulted in differences due to different wind products of up to 34%.

Automated Image Analysis of Offshore Infrastructure Marine Biofouling

In the UK, some of the oldest oil and gas installations have been in the water for over 40 years and have considerable colonisation by marine organisms, which may lead to both industry challenges and/or potential biodiversity benefits (e.g., artificial reefs). The project objective was to test the use of an automated image analysis software (CoralNet) on images of marine biofouling from offshore platforms on the UK continental shelf, with the aim of (i) training the software to identify the main marine biofouling organisms on UK platforms; (ii) testing the software performance on 3 platforms under 3 different analysis criteria (methods A–C); (iii) calculating the percentage cover of marine biofouling organisms and (iv) providing recommendations to industry. Following software training with 857 images, and testing of three platforms, results showed that diversity of the three platforms ranged from low (in the central North Sea) to moderate (in the northern North Sea). The two central North Sea platforms were dominated by the plumose anemone Metridium dianthus; and the northern North Sea platform showed less obvious species domination. Three different analysis criteria were created, where the method of selection of points, number of points assessed and confidence level thresholds (CT) varied: (method A) random selection of 20 points with CT 80%, (method B) stratified random of 50 points with CT of 90% and (method C) a grid approach of 100 points with CT of 90%. Performed across the three platforms, the results showed that there were no significant differences across the majority of species and comparison pairs. No significant difference (across all species) was noted between confirmed annotations methods (A, B and C). It was considered that the software performed well for the classification of the main fouling species in the North Sea. Overall, the study showed that the use of automated image analysis software may enable a more efficient and consistent approach to marine biofouling analysis on offshore structures; enabling the collection of environmental data for decommissioning and other operational industries.

CO2-mitigation options for the offshore oil and gas sector

The offshore extraction of oil and gas is an energy-intensive process leading to the production of CO2 and methane, discharged into the atmosphere, and of chemicals, rejected into the sea. The taxation of these emissions, in Norway, has encouraged the development of more energy-efficient and environmental-friendly solutions, of which three are assessed in this paper: (i) the implementation of waste heat recovery, (ii) the installation of a CO2-capture unit and (iii) the platform electrification. A North Sea platform is taken as case study, and these three options are modelled, analysed and compared, using thermodynamic, economic and environmental indicators. The results indicate the benefits of all these options, as the total CO2-emissions can be reduced by more than 15% in all cases, while the avoidance costs vary widely and are highly sensitive to the natural gas price and CO2-tax.

Produced-Water-Treating Systems: Comparison of North Sea and Deepwater Gulf of Mexico

In general, water-treatment systems in the North Sea differ from those in the deepwater Gulf of Mexico (GOM). The two most apparent differences are the extensive use of hydrocyclones in the North Sea, and the use of large, multistage horizontal flotation units in the deepwater GOM. Deepwater-GOM platforms use hydrocyclones, but not nearly to the extent that they are used in typical North Sea platforms. Typically in the North Sea, if flotation is used at all, it is a vertical compact unit. The objective of this paper is to provide an understanding of the reasons for these differences. In this paper, field data and modeling results are presented to explain these differences. The models accurately correlate the measured drop size and oil-in-water concentration observed in the two regions. In addition, the modeling tools are used to answer hypothetical “what if” questions. This allows isolation of individual variables such as fluid temperature, shear, separator residence time, and fluid density. Thus, the modeling provides a detailed understanding of the relative importance of these variables. It also provides a direct comparison of the performance of North Sea vs. GOM process configurations. While the qualitative conclusions are well-known (i.e., deepwater separation systems are designed to minimize weight and space), the detailed understanding provided here provides insight into the design of water-treatment systems in general. It also emphasizes, in a quantitative way, the importance of carrying out effective water treatment early in the process and the necessary use of large end-of-pipe equipment when this is not possible.

Decommissioning Costs Can Be Reduced

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25247, ’Decommissioning Costs Can Be Reduced,’ by Alan William Stokes, SPE, WorleyParsons, prepared for the 2014 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed. Reproduced by permission. Many offshore decommissioning costs are higher than necessary because of decisions made during the initial engineering and construction for an oil or gas field. Economics for a 60,000-BOPD oil field show that a reduction in decommissioning costs of 50% can increase the project net present value (NPV) by 13%. A 5-year range of decommissioning data collected from throughout the world has been studied. Key areas have been identified in which decisions made during design affected the eventual decommissioning costs. Introduction Decommissioning/removal of an offshore platform in 100 m of water is a complex project. Decommissioning of a platform in a severe environment can cost hundreds of millions of GBP. New-development project teams need to spend as much effort preparing for decommissioning in the design stage as they do preparing for the maintenance of the platform. Costs can be reduced during the actual decommissioning work by application of a contracting strategy and the use of previous experience and new technology. However, many costs are fixed because of the design features of the fixed platform or compliant structure. This paper provides guidance on how to engineer for decommissioning during the design stage of a new project. Project Economics The cost of decommissioning has to be included in the cash flow of the development because the late-life production rate is included. A typical North Sea platform in 80 m of water for a throughput of 65,000 BOPD with a 15-year field life has a cash flow that starts negative, turns positive, and then ends negative with decommissioning (Fig. 1). The final decommissioning cost before tax refund was estimated to be GBP 800 million. If the decommissioning cost can be reduced, the NPV of the project will be increased. Results of four NPV calculations as the decommissioning cost was reduced from GBP 800 million to 200 million are shown in Fig. 2. In halving the decommissioning cost from GBP 800 million to 400 million, the NPV of the project increases by 13%. These calculations assume a major short-term cash expenditure with the facilities being decommissioned using cash-intensive methodologies over 1 year. Other operators might want to design their new facilities to be decommissioned over a 4-year period at reduced cash flow, with consideration given to the knock-on effects of keeping utilities and the accommodation operable for the 4-year period. Significantly, the extended decommissioning project has an increase on the NPV of 30% because of the discount rate being applied to the decommissioning costs over 4 years rather than 1 year. When this 30% is added to the 15% increase resulting from cost reduction, the project NPV improves dramatically.

Oil and gas platforms with steam bottoming cycles: System integration and thermoenvironomic evaluation

The integration of steam bottoming cycles on oil and gas platforms is currently regarded as the most promising option for improving the performance of these energy-intensive systems. In this paper, a North Sea platform is taken as case study, and a systematic analysis of its energy requirements is conducted. The site-scale integration of steam networks is evaluated, based on thermodynamic, economic and environmental performance indicators. The penalties induced by operational restrictions such as (i) the use of a heat transfer loop, (ii) the demand for a heat buffer, (iii) the selection of a specific cooling utility, and (iv) the weight limitations on the platform are quantitatively assessed. The results illustrate the benefits of converting the gas turbine process into a combined cycle, since the fuel gas consumption and the total CO2-emissions can be reduced by more than 15%. Using the cooling water from the processing plant reveals to be more profitable than using seawater, as the additional pumping power outweighs the benefit of using a cooling medium at a temperature of about 8°C lower. This study highlights thereby the importance of analysing energy savings and recovery options at the scale of the entire platform, rather than at the level of the utility plant solely.

Managed-Pressure-Drilling Technology Succeeds in the Harding Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166170, ’Managed-Pressure Drilling, Casing, and Cementing Enable Success in Conventionally Undrillable Wells in the Harding Field,’ by Mohamed A. Mashaal, Tom Fuller, Chris J. Brown, and Robert Paterson, BP, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. This paper presents a case history of a North Sea well in which managed-pressure drilling (MPD) was used as the enabling technology to drill, case, and cement the well, with particular focus on the planning process, design methodology, and execution particulars. A novel fluid-pressure- transmission pill (FPTP), composed of a crosslinked polymer, was also used to maintain hydrostatic pressure while tripping bottomhole assemblies (BHAs) and during deployment of the liner and sand-control equipment. Background and Drilling Challenges The Harding field is a mature North Sea platform development upon which an infill-drilling project has been initiated to access the remaining oil. This oil tends to lie in more-distant, hard-toreach targets, including those in the far north of the field and a new field located south of the platform. These would be accessed by extended-reach-drilling (ERD) wells. A combination of reservoir depletion and weak interbedded sands and shales has resulted in a further reduction in the already narrow mudweight (MW) window between fracture and formation-collapse pressures. The window had decreased from 2 to 0.7 lbm/gal, equivalent to a 200-psi bottomhole- pressure (BHP) window. ERD to access the oil accumulations most distant from the platform would generate equivalent circulating densities that are 50% greater than the available MW window, so these wells are not conventionally drillable. After MPD proved to be an effective strategy for a test well (IC6) in the Harding field, the decision was made to apply MPD to two ERD wells (PNE4 and PNE2) that had not achieved their objectives. A subsequent investigation into the shortcomings of these wells led by the subsurface team resulted in a reworking of the pore-pressure/fracturegradient predictions for the northeast of the field, taking the depletion in that part of the reservoir into account. Sand/ shale interfaces at the margins of the reservoir, and sand/sand interfaces created by the injection of sand through the main reservoir body, also appear to result in localized fracture-gradient reduction. These combined factors resulted in a reduced MW window compared with that previously used in well planning. Hydraulics modeling strongly suggested that drilling PNE2a (the redrill of PNE2) would be unachievable conventionally, and drove the decision to use MPD for the reattempt. PNE2a would include a 12¼-in. overburden section, a highly challenging prospect containing more than 6,000 ft of shale, as well as the 8½-in. reservoir section, which was expected to have significant sections of shale where instability had previously caused drilling problems (see Fig. 1).

Multiwell Thermal Interaction: Field-Data Validation of Transient Model for Closely Spaced Wells

Summary Wellbore-temperature logs and associated field-history data from a high-pressure/high-temperature (HP/HT) condensate North Sea platform are presented that validate the accuracy of a transient model of the multiwell thermal interaction (MWTI). The model is an updated version of previous work by McSpadden and Coker (2010) that simulates transient thermal interaction or "cross heating" between closely spaced wells of a template. As discussed in the preceding work, the MWTI alters final wellbore temperatures as well as formation temperatures in the interwell zone and also farther out from the well template. The multiwell thermal model is shown to converge closely in very characteristic fashion to two different logged and measured temperature profiles at a vertical depth range of more than 3,000 ft. The empirical data, including field history, represent a unique opportunity to study and understand this important topic. Before this current work, the authors’ experience found the industry discussion of the MWTI or "cross heating" to be largely anecdotal. Model validation against field data is necessary to achieve a full understanding of the physical system and to provide confidence in the predictive capability. The modeling of wellbore and formation temperatures for closely spaced wells has not been widely examined in the industry literature, as observed by Bellarby (2009). The current work presents an improved methodology on the basis of standard-industry techniques. The method uses standard industry thermal/hydraulic modeling software for a single well and a fully transient finite-difference model for the formation in a loosely coupled, iterative analysis. The iteration scheme is achieved by the coupling of the standard analytical solution for the isolated single-well temperature scenario with the solution in the formation for the cross-heating scenario. The effect of the MWTI is important for closely spaced wells such as offshore platforms or subsea and Arctic developments. The multiwell disturbance on formation and wellbore temperatures may affect well design, facilities planning, and operations. For example, given nominal flowing wellhead temperatures (FWHTs) approaching 350°F for HP/HT platform developments, even small temperature increases may have a critical impact on the design and layout of surface receiving systems. Annular-pressure buildup (APB), wellhead movement, tubular-stress design, cement-slurry design, subsidence/compaction effects, and facilities health and safety issues can all be affected. If the MWTI is not taken into account, then load events such as APB, wellhead movement, and thermally induced stresses may be underestimated. Concurrent and batch-drilling operations, including cementation, will also be affected.

Exergy analysis of the oil and gas processing on a North Sea oil platform a real production day

We explore the applicability of exergy analysis as an evaluation and monitoring tool for the oil and gas processing on an offshore platform. A real production day on a particular North Sea platform is analysed. A process flowsheet is simulated using measured process data. We distinguish between temperature based exergy, pressure based exergy and the mixing part of the chemical exergy. It is shown that physical exergy in the material streams mainly is pressure based exergy, and most exergy destruction is related to decrease or increase in pressure. The sub-processes with most destructed exergy are the production manifold (4600 kW), the recompression train (4150 kW) and the reinjection trains (10,400 kW). At this platform 260 kW separation work is done, where a considerable part is done in the compression trains in addition to in the separation train. The specific power consumption is 179 ± 3 kWh/Sm3 and the exergetic efficiency is 0.13 ± 0.02. We propose measures to decrease exergy destruction, and that exergy analysis should be taken into regular use by the oil and gas industry. This study serve as a showcase on how to do an exact analysis of an existing offshore platform using measured process data.

Energy Efficient Pump Control for an Offshore Oil Processing System

The energy efficient control of a pump system for an offshore oil processing system is investigated. The seawater is lifted up by a pump system which consists of three identical centrifugal pumps in parallel, and the lifted seawater is used to cool down the crude oil flowing out of a three-phase separator on one of the Danish north-sea platform. A hierarchical pump-speed control strategy is developed for the considered system by minimizing the pump power consumption subject to keeping a satisfactory system performance. The proposed control strategy consists of online estimation of some system operating parameters, optimization of pump configurations, and a real-time feedback control. Comparing with the current control strategy at the considered system, where the pump system is on/off controlled, and the seawater flows are controlled by a number of control valves, the proposed control strategy has showed significant energy savings without sacrificing the system performance.

Frigg Decommissioning: HSE

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 21712, ’Frigg Decommissioning - HSE,’ by Bjorn Oscar Tveteras, Total E&P Norge A/S, originally prepared for the 2011 Offshore Technology Conference, Houston, 2-5 May. The paper has not been peer reviewed. The decommissioning of large North Sea platforms gives rise to significant health, safety, and environmental (HSE) challenges. These include a high level of work activity, numerous lifting operations, and work in an exposed area, all of which take place on a platform where the layout rapidly changes from day to day. Hazardous materials, such as asbestos, scale, and mercury, need to be removed and must be handled in a safe manner. Introduction The Frigg and manifold-and-compression platform 01 (MCP01) Cessation Project is the largest decommissioning project undertaken in recent years and includes removal of six topsides, three steel jackets, and sealines, with a final disposed-of weight of 87 000 tonnes. Different methods have been applied, from single and module-based lifts to “piece small” dismantling and removal. The Frigg field was a gas field in the North Sea, on the border between Norway and the UK. The field was developed with three installations in the Norwegian sector, a drilling and production platform, a treatment and compression platform (TCP2), and an unused steel substructure damaged during installation in 1974. Three other installations were in the UK sector, a treatment platform (TP1), a concrete drilling platform (CDP1), and a living-quarters platform. The platforms were installed in the period 1974–77. The produced gas was transported to St. Fergus in Scotland, through the Frigg pipeline, passing through MCP01 at the midpoint of the pipeline. The Frigg field production was shut down in 2004, with decommissioning starting in 2005 after cleaning of the process equipment/utilities and removal of most loose hazardous wastes. The Frigg field was the first large field to be fully shut down and decommissioned in the Norwegian sector of the North Sea. Three Frigg field substructures (TCP2, TP1, and CDP1) were made of concrete while the other three substructures were steel jackets. MCP01 also was made with a concrete substructure. None of the substructures have been used for storing crude oil. The concrete substructures were not designed and built for removal, and the assessment of the alternatives for removal and onshore disposal, or partial removal through cutting of the substructure, revealed too high a risk and uncertainty.