The North Sea Oil and Gas industry counts over 7,800 wells drilled. The industry is now entering an era of well abandonment and decommissioning. Current barrier verification for P&A requires appropriate pressure testing and includes surface and downhole monitoring. Globally, Spectral Noise Logging (SNL) has been utilized in many thousands of cases to detect fluid movement behind completion tubulars and/or across a cement barriers. In Nov 2017, full-scale verification tests were conducted at the International Research Institute of Stavanger (IRIS). These tests were conducted in a controlled environment to verify current technology thresholds. These showed the technique validated the cement barrier integrity during pressure tests and can diagnose channeling as low as 9 ml/min behind the casing. The threshold matrix for different cement defect versus pressure and flow rates allowed the usage of the technology to support the positive qualification of the barrier elements ( Dave Gardner, 2019 ). Utilizing a purpose-built test assembly of standard oilfield tubular and cement with fitted end caps, a series of pressure tests operations were conducted to identify the pressure and associate leak rates in conjunction with the SNL. The results clearly demonstrated that the logging tool can provide evidence of barrier verification over a wide range of well applications. Barrier qualification requires that three conditions are met; firstly, cement behind casing is in place and not displaying a micro-annulus or any form of fluid movement behind pipe. Secondly, that a cement plug holds pressure and there is also no fluid leak and finally natural shale barriers are active and create a sufficient barrier. Currently, technology is in its 10 th generation, and since the IRIS tests have been used in many wells, covering both onshore and offshore oil and gas wells and wells in highly sensitive environmental areas. On each case the logging operations were used to verify well status before and after the barrier establishment via cement squeeze or section milling and, in several cases, clearly, demonstrate that the barrier status remained ineffective, hidden and further remedial work was required. This paper discusses the downhole passive noise listening and its spectral analysis technique to prove the effective cement barriers are in place. The concept, methodology and its application which have been successfully tested via yard and field tests are presented in this paper.

This paper discusses the benefits of early plug and lubricate (P&L) of shut-in wells for Brent Charlie as part of the journey into the ultra-late life phase of the field. The Brent Charlie is the last producing platform on the Brent Field which is currently in its decommissioning phase, after 40 years of production. The integrated Well Engineering and Well, Reservoir & Facilities Management (WRFM) teams realised there were well and topsides facilities maintenance activities which could be streamlined or removed from the maintenance work scope. In the late life period of the asset the business driver is changing from "ensuring a well is fit for production to ensuring a well is fit for decommissioning". The work is focused on applying a fit for purpose approach to managing risks for long term shut in wells in preparation for plug and abandonment (P&A) with the rig. Performing offline P&L operations with a wireline unit ahead of the plug and abandonment work with the rig resulted in the following benefits: Removed integrity risks in the shut-in wells by ensuring the wellbore and annulus are hydrocarbon free. De-risked wells for plug and abandonment. Provided an opportunity to perform tail-end production optimisation. Optimisation of well-related maintenance scope leading to reduced spend. The adoption of an integrated approach to decommissioning and well abandonment resulted in cost savings and production gains that effectively paid for the P&L work.

This paper describes the successful application of a rigless well abandonment method that isolated the well's production interval using resin-based sealant, without cement and without latching a conventional subsea blowout preventer (BOP). An offshore operator needed to permanently abandon a subsea well that had become uneconomic due to excessive sand production. Several subsea wellhead and downhole conditions would have made killing the well by conventional means difficult if not impossible. Wellhead fatigue and soil erosion around the wellhead meant that a conventional drilling BOP could not be used in the operation due to the equipment's weight. Fluids to kill the well and permanently seal the formation could only be pumped down the tubing, and an obstruction in the flow path would limit the injection rate. Typical wireline and coiled tubing intervention tooling and circulation could not be used. Cement and micro-cement have particles that could potentially bridge at the downhole obstruction, preventing it from sealing the formation. Considering these factors, the operator and service provider designed, tested, obtained regulatory approval, and successfully implemented a rigless abandonment operation using a service vessel and well stimulation tool to inject resin-based sealant into the well to seal the formation and enable safe final abandonment and tree removal using a light intervention vessel. These results suggest that this method can potentially be used during abandonment of subsea wells with smaller trees and wellheads that have experienced fatigue.

This paper details the deployment of Spectral Noise logging confirming barriers in a complex abandonment of an onshore field in the Netherlands to fulfil regulatory requirements and to support sustainable abandonment. After initial plug and abandonment (P&A) activities on the main reservoirs, measurements showed pressure build up inside annuli. Spectral noise, high precision temperature and production logging were performed to determine the cause of sustained annulus pressure (SAP) and the location of leaks. The data acquisition was performed both under shut-in and pressure bleed-off conditions and both log responses were compared to identify changes in noise patterns. The noise from specific events such as channelling or reservoir activity was detected, so the abandonment program could remediate these issues successfully. Application of spectral noise logging in this field yielded evidence that this technology can identify annulus flow for very minor build-up rates (0.1 bar/day). This paper further demonstrates the ability to allocate the SAP source behind multiple barriers and to validate plug integrity. It was observed that noise responses have a good correlation with ultrasonic cement evaluation logs aiding better understanding of the gas migration mechanism and change in noise patterns. The temperature logging in most of the wells did not indicate any difference between shut-in and bleed-off regimes due to the very low leak rates. However, it did demonstrate the absence of any major cross-flow between formations. Insights in behind-casing flow geometry along the borehole helped to work out a remedial strategy to proceed with a sustainable abandonment of the logged wells. For specific and complex cases, where conventional pressure monitoring and pressure test techniques cannot provide conclusive results, the spectral noise logging technology becomes a useful differentiator in selecting between possible scenarios during execution, The technology therefore brings significant value by reducing project cost without compromising the quality of the abandonment.

Decommissioning activity will increase in the next nine years with a predicted £1.3 billion spent on decommissioning of subsea pipelines and associated subsea infrastructure in the North Sea from 2014-2023 [ REF 1 ]. Detailed preparation prior to the Cessation of Production (CoP) may significantly reduce this cost. Savings can be made during late in life operations on the platform and preliminary decommissioning planning. A Comparative Assessment tool assists the project team in selecting the most preferred decommissioning and abandonment option for subsea pipelines by using criteria such as safety, environmental factors, technical feasibility, economics and societal issues. These are then ranked by priority through matrix algebra. The introduction of new technology and advanced planning for decommissioning campaigns are the solutions for cost reduction, such as: Several applicable technologies and research areas are recommended as topics for further development, such as laser cutting, subsea lift claws and cutters and long-term effects of pipelines on fish habitats. A thorough checklist to incorporate decommissioning during the design phase would ensure decommissioning is given as much emphasis as input from the operations and maintenance teams during this important phase. Primary cost drivers are identified and include long term liability, cleanliness standards and national requirements for making the pipelines safe for potential re-use. Pipeline preservation for future use and/or leaving pipelines in place are the most cost effective solutions for pipeline decommissioning and if regulatory requirements change where pipelines must be removed, decommissioning costs could skyrocket.

Plug and Abandonment (P&A) is the largest category in Decommissioning expenditures, representing 40-44 percent of the total investment that basically comes as mandatory cost with no expected return. If the well operator gets P&A inadequate, results may include water flows, gas or oil seeps from the seabed, or underground cross flow between formations with huge impact on environment and marine life. The objective of this paper is plasma-based technology for enhanced casing section milling addressing the P&A challenges. According to some oilfield service providers, two main P&A challenges are as follows: Time and expense of casing milling - for example, Norwegian regulations call for cementing two 50-meter sections of casing above and below each hydrocarbon-bearing zone. Each section may take more than 10 days to mill and may generate four tons of swarf. The second challenge is swarf damaging blow out preventer (BOP) - Milling generates swarf, which then must be removed before cementing. However, swarf removal can damage the BOP. To avoid well integrity issues, BOP has to be dismantled, inspected and repaired at considerable expense. The presented paper is focused on technology eliminating the P&A challenges. The core of the technology is based on plasma generator producing high temperature water steam plasma for rapid steel structural degradation. This approach brings a radical abandonment of the classic rotary approaches with connected tubes in long strings and generation of swarf which need to be removed. Besides elimination of aforementioned challenges, the technology advantages include also rigless operation since the system is designed for coiled tubing solution. This feature brings additional cost savings using Light Weight Intervention Vessel (LWIV). Moreover, fully automated coiled tubing goes hand in hand with enhanced safety of the operational staff. Impact and potential of the technology is to change, simplify the process of P&A and therefore significantly cut the time of whole P&A. The technology is currently under development with expected commercialization within three-year period.

Mengkapan is a mature offshore oil field in the Malacca Strait PSC, located in central Sumatra, Indonesia. First oil flowed in 1986. The production wells produce multiple sands commingled with simple ESP completions. Cumulative oil production at the end of 2010 was 35 MMSTB, and the current recovery factor is around 50%. Over the years, as oil rates declined and water cuts increased, the team ran production log campaigns to monitor the oil rate and water cut of sand. These logs revealed the occurrence of cross-flow and oil-blocking, which was attributed to differences in permeability and pressure between the sands. The log results led to workovers to isolate high water-cut sands by setting production packers. But after more years passed, the point was reached where there were no more zones to isolate with packers, and the team was forced to consider well abandonment. Rather than abandonment, the team changed their mindset from "there is no remaining oil" to "there is by-passed oil and we can get it". The chosen technique was to squeeze-cement high water-cut zones and re-perforate by-passed oil sands identified from cased-hole logs. In ME-02, massive cross-flow between high-permeability sands seen in the production logs did not matter, because the suspected by-passed oil sands were the lower permeability sands at the top of the perforated intervals which were unaffected by cross-flow. The Carbon-Oxygen log suggested by-passed oil in the upper part of some sands. Next, all perforated intervals were squeeze-cemented, using a technique fine-tuned with the team’s knowledge of cross-flow. Then, the by-passed oil zones were re-perforated, and the well was completed and put on-line. Prior to squeeze cementing and re-perforation, ME-02 well produced 9000 BFPD, 45 BOPD. After the workover, the well produced 2000 BFPD, 104 BOPD. The budget was USD 660,644.00, but only 60% of the budget was used. It paid out in two months. This paper tells the failures by relying on a single tool and the success story in ME-02 to increase the value of a workover (reduced operation cost and increased oil gain), including the concept, the data gathering, and the field operation.

Abstract Reservoir connectivity is a key uncertainty when considering field appraisal and development options. Reducing this uncertainty can provide significant benefits in optimising the field development plan. Through the application of new wireless telemetry technology (Expro CaTS TM ), a fully abandoned subsea appraisal well has been cost effectively converted into a valuable reservoir monitoring asset. Clair Ridge appraisal well 206/8–13Y was drilled in 2006 and located some 8km from the existing Clair production platform. The well was the first step in an appraisal programme designed to confirm the next stage of development of the Clair Field. Reservoir connectivity and the risk of compartmentalisation are key uncertainties for development of the Clair reservoir (ref.1). On completion of testing operations, the well would typically have been permanently abandoned and of no further value for reservoir monitoring purposes. By installing a battery powered, wireless pressure monitoring system in the well at the time of final abandonment, it was possible to monitor for any fluctuations in the reservoir pressure in the Clair Ridge resulting from production / injection events on the Clair platform. This newly emerging wireless telemetry technology transmits data from the reservoir to the seabed using the well casing as the communication path and advantageously, the signal is not attenuated by the presence of cement or bridge plugs in the wellbore. The reservoir pressure and temperature data that is transmitted up the casing, is collected and stored by a CaTS subsea receiver located on the seabed. The stored data can be recovered, on demand, by a supply vessel located overhead using well established through seawater acoustic communications. The use of a wireless gauge enabled a downhole well abandonment to be performed. The traditional method for converting subsea appraisal wells for pressure monitoring has utilised a gauge and cable system (ref.2). This approach requires a relatively complex and costly semisub rig workover for final well abandonment. With the CaTS system, the well can be left fully abandoned downhole to UKOOA category 1 at the end of appraisal drilling. The remaining abandonment liability is just for recovery of the seabed receiver and final severance of the wellhead using a diving support vessel. This paper demonstrates that advances in wireless telemetry technology now enables critical reservoir data to be obtained from suspended/abandoned subsea wells or zones, where previously there was no cost effective means to do so. By monitoring the reservoir pressure variations in the abandoned Clair Ridge appraisal well, clear evidence of reservoir connectivity to the existing Clair platform reservoir area was demonstrated. This world first successful application of new wireless telemetry technology in a UKOOA category 1 subsea abandoned well marks a milestone achievement in advancing technologies that can cost effectively reduce uncertainty in reservoir connectivity at the field appraisal and development stages. Introduction The Clair field was discovered in 1977 and is estimated to have >4 billion bbl overall STOIIP, making it one of the largest discovered hydrocarbon resources on the UKCS. The field is located 75 km west of Shetland in water depths of up to 140 m and extends over an area of approximately 220 km 2 . Composed of fractured sandstones of Devonian age, it is the largest naturally fractured reservoir developed in the UK. Production from Clair began in February 2005 through the Phase 1 platform. This is a waterflood development specifically targeting reserves in the Core, Graben and Horst segments in the southern part of the overall Clair reservoir. The undeveloped field area is expected to hold considerable further reserves, but it is relatively un-appraised. The structurally elevated Ridge segments were identified as potentially the most prospective and a multi-well appraisal programme was developed. This programme also included extension of the original ocean bottom cable (OBC) seismic survey that was shot for development of the Phase 1 area.

Abstract This paper presents some of the issues which have influenced the decommissioning planning for the Heather Field facilities. The paper is based on the results of conceptual and pre-engineering work performed to date, and covers the following: – brief background on the Heather Field development and production history, field facilities, and achievements in extending field life to date, – considerations and constraints which have shaped Unocal's approach to the planning of the Heather Field decommissioning project, and – discussion of the stages to be undertaken in performing the decommissioning of the field facilities, concepts and options which exists for these stages, and operational and technical considerations applicable to each stage. The stages addressed include engineering and planning, well plugging and abandonment, topside systems cleaning and preparation for removal, pipelines decommissioning, topside facilities removal and disposal, and platform structure removal and disposal. Introduction The Heather Field. operated by Unocal Britain Limited, is located in Block 2/5 in the U.K. Sector of the North Sea, 145km east of the Shetland Islands. Oil was discovered in the Heather Field in December 1973 and first oil was exported from the platform in October 1978. Since 1978, in excess of 110 million barrels of oil and condensate have been produced from the field, with a peak average daily production of 36,000 barrels per day being reached in 1982. The Field has been developed with a combined drilling, production and quarters platform standing in 143m of water (Fig. 1). Processed oil and condensate is exported through a 32km 16" pipeline to Ninian Central Platform and onward to the Sullom Voe Terminal in Shetland. Natural gas is imported through a 19km 6" pipeline from the Welgas Pipeline for use as fuel and production wells lift gas. The Heather Platform jacket is an eight leg, tubular space frame, steel structure supported by six piles connected to each of the four corner legs. The legs have a 1:10.824 batter in the transverse direction and are vertical in the longitudinal direction. The jacket can accommodate 43 no. 26" diameter conductors which are laterally supported through slots provided in the conductor guide framing. In addition, two 16 risers are attached to the jacket, and nine caissons for miscellaneous services (e.g. process sump, utility sump, seawater lift caissons etc.) are supported within the jacket structure. The estimated weight of the jacket including piles and grout within the pile sleeves to the mudline is 17,300 tonnes. The well conductor weight to mudline is estimated at 4,300 tonnes, and the marine growth on the jacket adds up to another 2,000 tonnes to the overall weight of the platform structure. The topside facilities were prefabricated onshore and consisted of a relatively large number of "lift units" based on the lifting capability of the lift vessels available in the mid 1970's. There are three main deck levels, covering nearly 10,000m2, which contain all the equipment necessary for drilling and production operations together with numerous ancillary utility systems. The platform contains a skid mounted enclosed drilling derrick, two flare booms (each 52m long) and two diesel powered pedestal cranes. The total dry weight of the topsides facilities is estimated at 12,300 tonnes including the deck support frame (DSF). The Heather Field development has always been a marginal operation, but tight cost control, focused management and a "Fitness for Purpose" operating culture has enabled the Heather Field operation to remain economically viable. An aggressive infill drilling programme in the 1980's enabled additional reserves to be recovered, and more recently, application of coiled tubing based well intervention and stimulation techniques have slowed down the production decline rate. P. 135

Abstract Subsea wireline well intervention has been performed from the Multi functional Support Vessel (MSV) Seawell since I 988. In a joint Coflexip Stena Offshore (CSO) and Camco venture, an impressive track record in wireline work and abandonment has been created. Despite this, there is a growing need for developing the range of services to provide deep water well intervention and coiled tubing activities. This paper presents Coflexip Stena Offshore's current capability and experience and future strategy. This includes extending the range of the existing system for operations in water depths down to 3,300 ft (1,000 m) and modifying it to allow for riser and coiled tubing compatibility. The CSO Seawell is certified as an offshore installation capable of handling hydrocarbons at surface. Utilising a derrick structure, situated above a dedicated 22ft (7m) × 16 ft (5m) moonpool, well re-entry, wireline, pumping and abandonment tasks can be performed. Such tasks include gas lift, logging, perforating, cementing and setting plugs. Observation Remote Operated Vehicles (ROV) are an integral part of every well servicing operation, and the vessel can be equipped with a work-class Multi Role Vehicle (MRV). The first stage of developing Coflexip Stena Offshore's integrated subsea well intervention services is to extend the range of the existing system from 600 ft through to 3,300 ft. Modifications required include a new umbilical, incorporating an MRV operated panel on the lubricator and upgrading the lubricator winch wire and the four guide wires. The existing MRV unit has been successfully utilised in deep water diverless pipelay operations and can be fully equipped for well servicing operations. Following the above modifications a coiled tubing and tie-back riser system will be developed. This new system will allow for a smooth subsea changeover from normal wireline to tie-back riser activities by incorporating a high angle connector on the lubricator, compatible with the tie-back riser and the lubricator stuffing box. Coiled tubing equipment will be efficiently located on the vessel by modifying the existing equipment and vessel handling systems. This will include a purpose built injector head lifting frame to allow the injector assembly to be racked back into the derrick when not in use. A hydraulic control system will be required to power the coiled tubing equipment and will be a permanent feature on the vessel. Thus only an injector head and tubing reel would have to be mobilised for standard coiled tubing jobs, reducing time for overall mobilisation. The development of this integrated service from a dynamically positioned monohull will place Coflexip Stena Offshore in a unique position to take up the challenges of deep water West of Shetland and world wide. Introduction In Oil and Gas it has long been realised that cost savings and improved efficiencies in work methods are essential for the development of the industry, this is especially true in the North Sea in order to keep available investment from moving to other areas. One of the ways improvement can be made is for the North Sea industry to increase the efficiency with which assets are used. This is being done by looking for innovation in operations that will allow two or more tasks to be done simultaneously from the one offshore spread. This concept of simultaneous operations can involve the combination of any number of activities such as drilling, workover logging, pipelay, diving and general construction. This paper will focus on the simultaneous operation of diving services along with subsea well abandonment / servicing.

Abstract Well abandonment is now becoming an important consideration for many operators, particularly in expensive offshore locations. The traditional methods are very expensive to apply, and it is important to remember have a negative economic impact, other than good housekeeping. An innovative technique has been developed to enable all the well casing annuli to be permanently sealed in a single operation. A simulated well abandonment using this technique is planned for the summer of 1995 and the results will be presented together with time analysis and cost estimates. Introduction When production from a well drops below an economic level, the well may be stimulated, worked over or be subject to secondary and/or tertiary recovery techniques. However, the well will eventually require abandoning when it is no longer economic. Operators traditionally accrue for this eventual abandonment. However the costs of abandonment have soared due to inflation, and the higher costs of meeting ever stricter environmental requirements. Current techniques involve plugging each of the casings in a large number of sequential steps, then removing the casing. It requires the mobilisation of a rig and associated equipment to remove the casing from the well. A large cement plug is then placed to finally seal the well. The cost of the currently employed techniques are prohibitively high with operators often budgeting in excess of 650,0002 for abandonment costs. These high costs has forced operators to look at more cost effective methods1. However until now no cost effective method has been developed which could guarantee the long term integrity of the abandoned well. The technique proposed in this project will improve the quality and long term integrity of casing annul sealing at greatly reduced cost. The greatest assistance to oil companies can be given in the case of offshore where logistics and the environmental issues are more expensive to address. The techniques developed can be equally applied to land operations. Regulatory Requirements For platform structures - all well equipment and platform hardware has to be removed up to a minimum of 55m below sea level. For sub sea wells - the sea-bed must be cleared to 10 ft below mudline of all well equipment. For wellbores - all producing zones must be effectively isolated from each other. all producing zones must be effectively isolated from the sea-bed. all other potential producing zones that are either over pressured or hydrocarbon bearing must be effectively isolated from the sea bed. "effective isolation" is normally achieved with two verified cement barriers. Project Philosophy To significantly reduce the cost of well abandonment while matching current and potential future regulatory requirements, which will almost certainly involve post abandonment sampling of the seabed within an ever growing radius. By removing no casing or tubing from the wellbore avoids the use of a rig and the disposal of these used tubulars which potentially could have radioactive scale deposits. P. 53

Abstract The Argyll field came onstream in June 1975 and produced the first oil from the United Kingdom Continental Shelf (UKCS). The floating production concept adopted for the field demonstrated an innovative cost efficient approach to developing a marginal field. The initial field life expectancy was three to five years and cost sensitivity was embraced as the only viable way to ensure that the field survived longer than originally forecast. This paper reviews some of the Argyll field innovations from initial design into ongoing operations and on through to abandonment. Technical solutions which result in low capital investment but then give higher than preferred operational costs, do not necessarily result in reduced field life. A "Tight' approach to operational cost control is vital in the early years of a field's life so that later year cost control is a natural progression and not a desperate rearguard action. Cost control is a state of mind and must be engendered into the Ethos of a company. The question, why?, is probably the most powerful tool that any individual can apply in the approval process, no matter the level of that approval. Expenditure approval set at an appropriate level coupled with staff committed to a continuous search for improvement, results in an operations group which manages their own business, This level of understanding acts on market changes rather than reacting to change, thus resulting in true cost control. Introduction Hamilton Oil Company Ltd. (Hamilton Brothers Oil and Gas) was Operator of the Argyll field in Block 30/24 of the UKCS in conjunction with other field owners, Elf Enterprise (Caledonia) Ltd., Texaco North Sea UK Ltd., Lasmo (ULX) Ltd., and Monument Resources., from first oil in June 1975 to last oil in October 1992. During that period two satellite fields were added to the Argyll system, Duncan in 1981 and Innes in 1985. The initial, albeit uncertain, reservoir assessment of recoverable oil for the Argyll area was 25 million barrels over 5 years. Argyll ultimately produced 73 million barrels, Duncan produced 19 million barrels and Innes produced 5 million barrels. The total production from the field complex was 97 million barrels of oil over a 17 year period.

Abstract Abandonment timing for Thistle is uncertain, and the aim of reservoir management is to accelerate reserves so that value is maximised prior to a target date. In an environment of tight expenditure control, the focus has shifted front large field studies to well reviews, and from infill drilling to recompletion. Introduction The Thistle Field lies in the north of the Brent Province in the UK North Sea (Figure 1). It shares many of the key geological and production characteristics (Reference 1) of other Brent tilted fault block fields in the area (Table 1). Figure 1. Thistle Location Map Table 1. Thistle Field Data Trap / Reservoir Type Rotated Brent fault block Reservoir Middle Jurassic Brent Group Thickness 550ft max. Type 8 layers, fault compartmented Crude Oil Gravity 38.4 dg API GOR 290 SCF/bbl Reservoir pressure 6060 psig at 9200 ft TVDSS Bubble point 960 psig STOIIP 824 MMSTB Figure 2. Reservoir sand permeability distribution P. 347^

Abstract A campaign in the North Sea was carried out to permanently abandon 24 wells using coiled tubing (CT). permanently abandon 24 wells using coiled tubing (CT). This was used to fulfil the Department of Energy requirement that the production screens had to be plugged back with cement prior to the removal of any plugged back with cement prior to the removal of any well completions. A review of the advantages of using CT and the operational difficulties experienced during the placement of the cement are presented. A financial comparison with present day abandonments, using a rig for the entire operation, is also presented. Introduction The recent surge of interest in cementing through CT in the North Sea is based on the results achieved in Alaska. In 1983, ARCO, Alaska pioneered the use of CT for cement squeezing during workover operations in the Prudoe Bay field. A few years later BP Exploration Prudoe Bay field. A few years later BP Exploration followed suit. The principle motivation for using CT for cement squeezing is economic: to reduce workover costs in an environment where rig mobilization and operational costs are becoming prohibitive. Significant advantages have been identified by using CT for remedial cement squeeze operations: * Since well pressure control can be maintained at the surface through a stripper and a blow-out preventor (BOP) assembly, it is possible to run intolive wellbores. * Existing production tubing and wellheads do not have to be removed to access the production interval. * Possible slurry contamination during the placement is minimized. * Since the CT can be reciprocated while pumping, exact spotting of a small volume of cement slurry at the zone of interest is possible. It was this economic interest that led Elf Aquitaine, Norway to consider CT for part of their CDP-1 Platform abandonment project. FRIGG GAS FIELD Frigg is a "dry gas" field located on the Norwegian-UK border. It was discovered in 1971 and put on stream in 1977 from two 24 slot production platforms. The initial gas in place is estimated to have been 235 BSm3, with final recovery estimated to be in the order of 177–180 BSm3. The average monthly flowrate has been as high as 70 MMSm3 /day due to pre-sale and banking arrangements with the fields connected to the Frigg transportation system. The reservoir consists of friable sands of Lower Eocene and Paleocene age with very good poro/perm characteristics. The initial gas column was up to 525 feet (160m) thick and overlying a thin oil rim. P. 117

Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper was presented. Publication elsewhere is usually granted upon request provided proper credit is made. Abstract The publishing of the UK Government's "Petroleum Bill" has generated much interest and controversy in the subject of Removal and Abandonment of offshore installations; it is therefore particularly timely to review all the influences that may affect the situation and update the position for 1987. It has now become apparent that there are many bodies, governments and other factors that may generate an impact on Removal and Abandonment and this paper starts with a brief outline of the situation in 1986. New influencing factors are then introduced and reviewed and the likely impact of these influences assessed. The paper concentrates on the UK sector but all the various influencing factors are equally relevant to the whole of the North Sea. Introduction The UK Government's Petroleum Bill was published in November 1986. Prior to publication, it was already clear that this was to be an enabling Bill and that no clear definition of requirements would be included. The Bill subsequently became law in April 1987 after amendment of certain financial provisions. The oil industry's prime objective was to pursue the most cost effective methods of dealing with Removal and Abandonment and it was established in 1986 that total removal would be necessary in shallow water, i.e. 30-40 metres, and that toppling platforms in place would be the lowest cost method where water depths permit. The proposition to leave platforms on-site equipped with "fairy lights" was not considered a practical long-term solution. Concrete platforms would need to be refloated and towed away for disposal, unless an alternative method of disposal on site can be developed. It was clear that many factors, not directly connected with the oil industry, would have a major impact on Removal and Abandonment methods. 1987, up to the time of writing, has highlighted the differences in interpretation of International Law and the effect of Removal and Abandonment proposals on the safety of navigation. Representatives of the fishing industry have always expressed their concern with regard to what happens to the platforms at the end of their working lives and their views on the safety of fishermen are very important.