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 will describe how fiber optics can be introduced into wells at very low cost, for the purposes of Distributed Temperature Sensing (DTS), using a novel disposable deployment method. It was identified that the cost and risk associated with existing methods of installing fiber optics have. severely restricted the application of downhole distributing fiber-optic sensing. It’s because of this that technology has been developed that is cost effective enough to run in any well, resulting in a disposable system that uses the required materials to perform a singular operation. The system utilises bare fiber optics, located in the tool, referred to as ‘dart’ herein. The fiber optic is de-spooled during free-fall deployment into the well. The system is disposed of in the well following the distributed sensing operation, which would typically only last several hours. Tests performed in a shallow test well have shown that bare fiber optic can be successfully and reliably deployed into the well and that a Distributed Acoustic Sensing (DAS) survey can be performed on each fiber installed. It was observed that the bare fiber was paid out into the well with no detectable slack, resulting in good depth correlation, important for determining the location of any event. It was also observed that the bare fiber attached itself to the inside of the tubing, which is thought to provide a good acoustic coupling - as well as a certain level of protection versus a freely moving fiber in the well. It was concluded that the novel system is viable for use in oil and gas wells and would provide significant cost and risk reductions compared to existing methods of fiber deployment. The resulting increase in data from the application of such a system would have a considerable impact on production and well integrity, as well as offer vast cost savings in well abandonment operations.

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.

For the majority of older oil and gas facilities, the production and processing environment has changed significantly since its early days, with increasing operational and maintenance overheads and obsolete control technology often threatening to bring lift costs above production revenues. As a result, Production and Operational Efficiency has significantly worsened in recent years with many of these assets performing well below optimum production, equating to approximately 500,000 barrels of lost production per day in the UKCS or £10bn/annum (based on Oil and Gas UK production availability figures) Enquest's Thistle platform was one of these assets and was due to be decommissioned until the brave decision was taken to extend its life by putting in place the Late Life Extension Program (LLX). Using groundbreaking Asset Life Extension techniques and methodologies, this old facility is in the process of being re-designed by simplifying the topsides which in turn, is leading to improved availability, increased production and reduced operating costs. A simplified, safer process in a controlled environment has been created whilst balancing the requirements of a capital budget, against reduced OPEX and process risk. It is estimated that the modifications have added at least 15 years of safe, viable, profitable production to the Thistle's lifespan, a great example of deferring decommissioning and Maximising Economic Recovery.

A new program for the development of graduate engineers has been implemented in Denmark on a stimulation vessel in the North Sea. It is designed to provide graduate engineers with a three-year period of extensive experience in offshore operations, knowledge of equipment and designing effective stimulation jobs. There are many components to the program that address training, skills, demonstration of capabilities and evidence of competence. These are essential components that ultimately lead to improved operational performance and highlights. The North Sea oil and gas industry requires a constant effort to maintain the engineering skills of its offshore workers so vital to continued success. Paradoxically, there are numerous factors that hinder on site development of young engineering talent in the North Sea. There is a lack of offshore accommodation that often restricts onsite time for trainees. This is exacerbated by a low frequency of many operations compared to other provinces in the industry. A further barrier arises from the costs associated with the extensive obligatory HSE (Health, Safety and Environment) training requirements before going offshore. In general, these factors are getting more difficult to manage with time. The North Sea vessel provides an excellent environment for the program with a number of aspects that are very important to graduate engineers. Firstly, the vessel has a design life of 30 years and so provides confidence in the prospect of a long term career. Secondly, the vessel has the newest technology and a large number of experienced personnel on board to act as mentors. Thirdly, the vessel performs operations regularly and fourthly, it has plenty of bed space. In addition, the vessel boasts excellent welfare. Each person benefits from a single occupancy bedroom which has natural light and is en-suite. It has a first class free restaurant and great recreational facilities. Participation in the development program provides the opportunity to work and study at the sharp end of the industry, overcome exciting tough technical challenges and most importantly a vehicle to developing a meaningful long term career.

When two wellbore barriers are set in close proximity it is difficult to determine if the upper barrier plug is holding pressure. Measuring the liquid volume pumped to achieve the pressure test does not always provide adequate assurance. The wireless Barrier Verification System (BVS) was developed to meet the demand for barrier plug integrity assurance. The system consists of a pressure sensor with a transmitter attached below the barrier plug. A Receiver is mounted on top of the installation tool to wirelessly record the pressure measurements below the plug. An additional pressure sensor forms part of the receiver to provide an accurate reference pressure measurement above the plug. The transmitter sends pressure readings and can record for multiple days depending on battery selection, wellbore temperature and logging frequency. The Receiver also records and stores the reference pressure information collected above and wirelessly from below the barrier plug. For Slickline conveyance, the system will be configured for readout of the memory after the Receiver is retrieved. Real-time readout to surface is an option when used on E-line. The wireless BVS system was first used in the Norwegian Continental Shelf (NCS), mounted on a 5.5″ Medium Expansion (ME) Retrievable Bridge Plug, and on an 3.5″ Electronic Setting Tool (EST). Following the setting of the barrier plug, it was pressure tested from above. The graph showed a differential pressure across the barrier plug which verified and provided assurance that the plug was holding pressure (Pressure above ~ 450 Bar and pressure below ~ 230 bar).

When setting two deep wellbore barriers in close proximity it can be difficult to be assured that the upper barrier has integrity. Only by measuring the pressure between the barriers can the integrity of the shallower barrier be verified. Well abandonment practice is dictated by territory specific regulations which are largely based on historic practices. However, emerging technologies and methodologies are gradually changing the outlook, affecting the way we carry out future P&A operations. With the introduction of any new methodology or technology there is a need for verification and testing of the permanent barrier. Currently, the typical concept is to use an anchoring or plug device to build a barrier above. The wireless BVS (Barrier Verification System) uses ELF (Extreme Low Frequency) telemetry and has the capacity to transfer signals through the barrier or surrounding wellbore/lithology to a receiver above the established seal. The system consists of a pressure sensor with a transmitter attached below an anchoring device. A receiver is lowered on slickline or electric-wireline above the barrier to be tested. The receiver wirelessly records the pressure measurements transmitted from below the anchoring sealing device. An additional pressure sensor in the receiver forms part of the toolstring to provide an accurate pressure reference above the established barrier for verification testing. The transmitter can record for multiple days depending on battery configuration, wellbore temperature and logging frequency. The receiver can transmit real time data or it can be deployed in memory mode for slickline, coiled tubing and pipe-deployment applications. The objective of this paper is to examine and explore the technology of the BVS, the design and development, the qualification tests carried out, and the execution and results of an operation in the North Sea.

Abstract A technological breakthrough within the application of wireline technology has been achieved. In August 2008, on an offshore platform in the Norwegian Continental Shelf, a wireline tractor and a new wireline milling system were used to mill and remove a permanent bridge plug at 4,147 ft MD. The operator decided to mill out the plug on electric wireline and worked closely with the service company to develop this novel solution. Having developed and tested several bits and milling tools, results showed that by combining the wireline miller with hydraulically provided weight on bit (WOB), it would be possible to mill out the retaining rings of the plug, which would cause the plug to collapse. The milling control unit allows the WOB to be adjusted for each application and also controls the reactive torque, the force generated when the milling bit engages the plug. The service company was able to develop the solution within the client's parameters and in accordance with the timeline set out for this project. The offshore operation was completed in three days to the operator's satisfaction. In another platform well, a permanent bridge plug had been set in 2003 in the sealbore between two screen sections (3 ft sealbore, 67 degree well angle, 4.75" ID). The plug was set in order to isolate the fairly higher watercut in the lower reservoir zone to prolong oil production from the well. In 2006, the well drowned after a two week maintenance period. Two years later, a coiled tubing (CT) gas lift operation was carried out with good results. It was then decided to remove the permanent bridge plug to re-open for production before another CT gaslift operation was carried out. A method for milling the permanent bridge plug was developed based on lessons learned from the other plug milling operation and by extensive testing at the service company's facilities. The operation was successfully completed in 13 days. This new application for milling completion hardware and other wellbore obstructions offers a cost-efficient alternate technology to existing methods. The success of the milling operation is quite an achievement and has pushed the limits for what is possible on electric wireline. This paper will examine two cases of milling bridge plugs on electric wireline and the technical challenges that had to be overcome in offshore operations. The first using the well stroker as WOB, the second using the well tractor as WOB.

Abstract Oil was first discovered in the North Sea in the 1970's and some of platforms that were erected during that era are still producing albeit the production has dwindled significantly. With the technical costs on the rise oil & gas operators are constantly on the lookout for cheap and simple solutions. These help not only to increase the hydrocarbon production from a well but also helps in improving the overall field recovery factor. However, sometimes expensive well interventions are necessary in order to better understand the problems faced and then use the data acquired to study and then implement a more long-term/ permanent solution. The purpose of this paper is to present details on what kind of solutions that have been implemented within the Alwyn field (producing since 1987) in the Northern North Sea. These production enhancement measures relate to a number of different disciplines ranging from topsides modifications to well interventions to sub-surface. As these disciplines originate from different departments within the Company a well performance team was created with the objective of coordinating all production optimisation studies and their implementation on the field. During the course of this paper more details about the structure of the team would also be provided along with further justification outlining how the team has helped in increasing the production from a number of wells. A large variance in production gain has been observed from these operations dependent on the nature of the intervention this ranged from 50 boe/d to nearly 2,500 boe/d. Introduction The literal definition of the word "optimisation" from the Compact Oxford English Dictionary is defined as "make the best or most effective use of (a situation or resource)". Production normally needs to be optimised once the producing assets mature and the production start to dwindle from the plateau. In this scenario the production from each well needs to be carefully analysed and then maximized to ensure as high a recovery factor as possible. A wide number of production optimisation measures are currently being implemented on the Alwyn platform in the Northern North Sea of the coast of Scotland. The Alwyn North Field is located in block 3/9 of the UK Northern North Sea (see figure 1 below). It is approximately 500 km (300 miles) northeast of Aberdeen in 130m of water. The Alwyn North installation comprises of two platforms linked by a bridge. The NAA Platform consists of drilling facilities, miscible gas injection, utilities, offices and accommodation. The NAB Platform consists of oil and gas processing and export, water injection and utilities.

Abstract When operators are faced with issues involving casing leaks, a typical course of action is to pull the tubing and make efforts to identify and locate the source of the leak by logging or other mechanical means. If the leak source can be successfully located, a mechanical method is generally employed to patch the leaking casing. This methodology is time consuming and expensive. Locating casing leaks with the tubing in place using conventional logging techniques has historically been difficult. Where some tools, such as temperature tools, may provide an indication of an anomaly in annuli, the data may be subjective or the leak may be too small to measure. When active, a leak will produce a spectrum of sonic frequencies that may be either audible, ultrasonic or both. Ultrasonic energy will pass through steel but travels relatively short distances. A tool developed around these principles has been successful in accurately locating casing leaks behind tubing. Pressure-activated sealants have been used for a number of years to cure a wide variety of leaks in casing, tubing, control lines, and well heads as well as micro-annulus leaks in cement. For the purpose of repairing a casing leak behind tubing, the liquid sealant may be pumped into the annulus and displaced to the leak site. The liquid sealant will not polymerize until it is exposed to the differential pressure through the leak site. Knowing the leak rate, pressure and precise location of the leak aids in the selection of the sealant formulation and deployment method. This helps to reduce overall repair cost as well as increase the probability of a successful repair. This paper will describe the ultrasonic method of leak detection and the method of curing leaks with pressure activated sealant with tubing in place. Case histories will be presented where these methods were employed to repair casing leaks without removing the tubing. Introduction Perhaps the most challenging well integrity issue with which operators deal with today are casing leaks. Not only are the methods to repair these types of leaks without pulling the tubing limited, but the detection of these leaks using conventional logging methods with the production tubing in place is practically impossible. A common diagnostic methodology is to rely on some fairly subjective logging data and pressure responses to determine where a pressure barrier is leaking. Following this, cement is pumped down the annulus or through punched tubing in an attempt to seal off the leak. This process, along with other hardening sealant methods, can be problematic. Additionally, using this method will also make other operations or future workovers difficult or impractical. Pressure activated sealants have been used on numerous occasions to repair casing leaks with the tubing in place. A major advantage in utilizing this technology is that the sealant will only solidify where the leak is active. In addition, the material is easily removed by mechanical means and will not add difficulty to future workover operations if required. As is true with other remediation methods, a complete understanding of the leak source is critical when planning a pressure activated sealant operation. This is especially true when dealing with leaks behind the tubing. Optimal sealant formulations may be selected along with deployment methods for maximum affect. While rate and differential can be determined by pressure and well bore data, a leak behind casing is more complex. Detection of casing leaks is difficult using conventional logging techniques. These leaks will produce no reading on spinners (for obvious reasons) and may not produce temperature changes that are of a magnitude to confirm a leak point. This is true even with fairly large leaks (>1gpm). Conventional noise logs can detect fluid or gas movement, but must be used in a stationary mode and distant noise sources may confuse interpretation. Tracer logs may be used but can also produce imprecise results. The ultrasonic leak detection method has been proven to be useful in detecting leaks behind casing with a high degree of accuracy. This suggests that it would be a useful tool in evaluating wells for repair using a pressure activated sealant method where accurate spotting of the treatment is critical.

Abstract A further evolution of wireline intervention technique has emerged allowing mechanical manipulation in horizontal wells using a combination of Wireline Stroker and field proven Wireline Tractor technology - best described as Well Construction on wireline in a highly deviated well. This technology represents a cost-efficient method for setting and retrieving of specific downhole hardware (i.e. plugs and straddles) as a resource-efficient alternative to existing technologies. This paper will present the following case history and the benefits of the operation, particularly in deviated wells, where tractor technology in combination with the Wireline Stroker exemplify the advantages of this technology. In a well offshore Norway, producing since 1995, completed with 2 Sliding Side Doors (SSD) to control zone production, attempts had been made to close both SSD's in October 2003, but only the upper SSD was possible to close. A two-piece straddle was sat above the lower SSD, which however showed no change in production. PLT results showed an internal leakage in straddle and tubing; straddle was therefore retrieved in February 2006 and the well temporarily plugged. Later in 2006, it was decided to perform a new intervention in order to remedy the situation and a Tractor/Stroker combination was considered optimal for performing the operation, as an alternative to a Coiled Tubing operation. Introduction Well P-24 is an oil producer at Snorre A. It is a 5 ½" monobore deviated well completed in 1995 with perforations in the Upper and Lower Statfjord sands in both the Western Fault Block (WFB) and in the South Western Fault Block (SWFB). The well has produced 4.6 mill Sm 3 oil since it came on production in 1995. In 2003 the water cut level was increased to more than 80%, the GOR was 2100 and the oil rate had dropped to 100 Sm 3 /day. It was anticipated that the high water cut and GOR mainly came from S1 and S2 in the WFB. The P-24 completion design allows these sands to be isolated by two mechanical sleeves and in 2003 an intervention was planned to close the sleeves in order to shut off the production from these zones. However, this intervention was not successful as only the upper sleeve was closed. A 2-section straddle was installed across the lower sleeve using tractor on wireline, but the well production profile remained unchanged. A PLT log indicated a leakage in the straddle.

Abstract Well service activity in Shell's Northern Business Unit is outsourced to an integrated services contractor with targets set for HSE, quality, and cost management. Various key performance indicators are measured to provide the necessary focus for control and improvement. Historically this focus has been on operational time improvements and associated rig day-rate savings. However, approximately 25% of annual well services expenditure represents equipment rental charges and hence any efficiency improvement can have a major impact on budget performance. In 2001 a system was introduced to track and co-ordinate the movement of all rental equipment deployed offshore. By closely monitoring the status of all items from loadout to return, baseline efficiencies were established. Using Supply Chain Management techniques such as Just-in-Time shipping, opportunity scheduling and influencing sub-contractor pricing has lead to utilisation efficiency improving from 48% to 62% in 2002, equivalent to over £0.5 million of eliminated costs. As fields mature and well interventions represent a greater portion of operating expenditure, this type of saving could ultimately make the difference between extended field life and final abandonment. Management of Well Services Shell UK Exploration & Production's Northern Business Unit comprises the Brent, Cormorant Alpha, North Cormorant, Dunlin, Eider and Tern fields located in the northern North Sea approximately 300 miles north-east of Aberdeen. These platforms require an intensive and ongoing well intervention and maintenance programme in which expenditure is closely scrutinised and elimination of waste and inefficiency is seen as an imperative. In 1994 Shell outsourced the management of well services to a single integrated service lead contractor, responsible for planning, programming and execution of activities using selected sub-contractors for key services (wireline, coiled tubing, TCP perforating and slickline data acquisition). Initially the contract was to manage the Cormorant Alpha, North Cormorant, Dunlin, Eider and Tern platforms; however in 1998 these assets were combined with the Brent field to create the Northern Business Unit (NBU). The contract was re-tendered in 1999 to include this increased scope with a five-year contract term. One of the key contract objectives was to use the stability created by the five-year term to drive Supply Chain Management improvements that would lead to greater cost efficiency. In particular, the value of spend on sub-contractors rental equipment was identified as a key area for cost savings. Large quantities of equipment are mobilised to conduct the various completion and well service activities, with much of it on hire from the time it leaves the sub-contractors base until return thereto. For a large part of this time the equipment is not being used, and hence minimising the mobilisation, standby and shipping times is an obvious way to reduce costs. Previously this had been achieved via morning calls, daily reports and informal enquiry between the onshore and offshore well services teams. It soon became apparent that with the increased level of activity across nine platforms, an effective method of tracking and monitoring the use of personnel and equipment would be required to deliver further improvement. Equipment Tracking and Data Management A software based system of tracking the exact location, status and cost of sub-contractors equipment was developed to assist the operations engineers, and to visibly highlight areas of waste. By updating the system daily, equipment is tracked as soon as it is mobilised from the sub-contractor, and its status recorded depending on whether it is in transit, awaiting use, in use, or out of service. By tracking each package of equipment in this way, it becomes readily traceable and subject to closer scrutiny, so improving the overall resource management process.

Abstract In the past, high-volume water-shutoff treatments have not been applied because of the economic burdens they incur. Today, many operators have reconsidered high-volume water-shutoff treatments because these treatments make oil production from mature reservoirs more economically feasible. Many wells in mature North Sea reservoirs produce a large amount of water. Consequently, these wells often produce less oil than they potentially could. The evolution of diagnostic and interpretation techniques has significantly enhanced the degree of accuracy and completeness of production problem diagnoses. Reservoir models can be used to identify and design effective water-shutoff treatments. This paper describes how a production operation simulator is used with an advanced-processes reservoir simulator to design water-shutoff treatments. The following reservoir simulator options were necessary to design the treatments properly. – thermal options – chemical-injection options – chemical-reaction options – flexible-gridding options The technique was recently used to design water-shutoff treatments and their placement for jobs in the North Sea area. The results of the simulations were used to predict the effects of the following factors. – interval permeability distribution – treatment rate – reaction rates of treatment fluids – resulting gel strength The technique also allows treatments to be designed on the basis of realistic treatment temperatures rather than bottomhole static temperatures. The results of the simulations were used to optimize treatment placement rates, fluid composition, and shut-in times of jobs pumped in the Norwegian sector of the North Sea. One case shows how cooldown inside the reservoir can be used to place a treatment that would have otherwise spontaneously gelled at reservoir temperature. Another case shows how temperature histories for different stages of the treatments were constructed from the simulation results. These temperature histories showed that different activator compositions and/or concentrations were required for early, intermediate and final treatment stages. Introduction Water production can seriously compromise the profitability of oil- or gas-producing wells. The cost of produced-water disposal is becoming a major burden for many operators. Although prevention is usually more effective than treatment, excessive water production is most often treated rather than prevented. The keys to the success of shutting off or preventing excessive water are: – proper identification of the water-production mechanism – appropriate design of the treatment – effective placement of the treatment Steps of Typical Water-Shutoff Treatment Figure 1 illustrates the process of a typical water-shutoff (or conformance) treatment. Each step of the process will now be discussed. P. 611^

SPE Member Abstract Several North Sea Operators are now using Snubbing Units to undertake operations previously regarded as only within the scope of a drilling rig (such as the running of 7" completions and the undertaking of gravel-packing operations). Snubbing Units are also increasingly being used to access and service horizontal and extended reach wells which coiled tubing cannot access. With the use of a Snubbing Unit, through-tubing side-tracking and underbalanced drilling is no longer limited by the technology of Coiled Tubing Drilling. Additional margins are available if a 'Snubdrill' option is adopted and these are quantified with the presentation of the results a 'Snubdrill' Case Study. Snubbing Units can therefore now be regarded as an established means of providing an Operators with a versatile and unique device which offers many advantages over both Derrick Equipment Sets and Coiled Tubing Units. Introduction A Snubbing System is basically a well servicing system capable of running and retrieving jointed pipe under live wells conditions. A typical Snubbing System is illustrated in Figure 1. The use of a Snubbing Unit is not only already providing cost effective technology for a wide range of Drilling and Well Servicing applications but also has the potential for providing an alternative way to optimally develop future fields. Present Snubbing and Hydraulic Workover applications include the undertaking of remedial well work without resorting to the use of kill fluids or lost circulation material and the performing of conventional tubing replacement workovers Snubbing well intervention operations are also now routine where coiled tubing operations are not feasible due to well bore geometry or length and should be considered where platform facilities are unable to handle the weights of larger coiled tubing reels. Historically, workovers performed through existing tubing ('through-tubing workovers') have been undertaken with wireline or coiled tubing equipment, often supported by the use of a derrick equipment set. Snubbing systems are now performing similar work and are proving to be far more versatile than wireline coiled tubing and conventional workover rigs with the additional ability of being able to run and rotate tubulars while there is pressure on the well. Although certain workover situations will still call for wireline coiled tubing or workover rigs, there are now many situations where a Snubbing Unit is the logical choice. In principle, all of the downhole work that can be carried out by standard rig or through-tubing workover equipment can also be completed by Snubbing Units, with the (current) exception of running large >10 3/4") tubulars. Future applications for the technology include the horizontal side-tracking of existing wells (which could be performed conventionally or underbalanced). Such operations can either be undertaken through the existing tubing or, where such operations are not deemed feasible, the Snubbing Unit can be used to pull the existing completion prior to the side-track and used for the subsequent running of the liner and completion after drilling. One of the main advantages of utilising Snubbing equipment is the ability to undertake a whole variety of operations and hence supply the versatility that has, up to now, only been regarded as available from a full derrick equipment set in combination with wireline or coiled tubing equipment. P. 439

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 Operational support functions are an important consideration in the development of offshore reserves and must be administered in such a manner that prevailing environmental regulations, personnel safety, and the local environment are not compromised. At the same time, the economic burdens imposed by their administration must be compatible with production forecasts. This paper will discuss a unique support approach that was codeveloped by BHP Petroleum Limited (BHP) and the engineering staff of an international oilfield servicing/manufacturing company to support the operational objectives for the Hamilton, Hamilton North, Douglas, and Lennox fields in the Liverpool Bay Development. A key component of the concept is a manned, self-elevating Operations Support Vessel (OSV) that can provide cost-efficient infield service to the offshore platforms in the developed locations while maintaining all safety and environmental requirements. The OSV concept has enabled the operator to develop fields in shallow water with unmanned, minimum-facility, standardized platforms that are consistent with the industry "Cost Reduction in the New Era" (CRINE) initiative, When multiple fields are within reasonable proximity, the economic advantage gained with this vessel is enhanced even further. The success of this approach brings a cost effective solution to the development of offshore reserves in shallow waters that cannot support the economic burdens of traditional North Sea manned platform designs. This approach to field development for the UKCS has resulted in a life-cycle operating contract between BHP and the servicing company. This interaction has not only enhanced current operational technology within the required parameters but also illustrates a practical example of an industry "win-win" relationship. Introduction Developmental philosophy for offshore fields in the U.K. has undergone significant change within the last few years, primarily from the need to address the depressed economic climate resulting from reduced oil and gas revenues at a time when operating costs have continued to escalate. In addition, environmental regulatory standards have become more stringent, further impacting operational costs. During 1993, it became apparent that without stronger emphasis on cost reduction, operational feasibility in the North Sea would be seriously impaired. Thus, the desirability of restructuring operating procedures to the practicable doctrines of the CRINE initiative gained new importance in operational strategies. BHP had begun exploration for oil and gas in the Irish Sea in 1990. Since then, both oil and gas discoveries have been made, and a substantial effort has been put into planning the development of these resources. With the impending development of the offshore Hamilton, Hamilton North, Douglas and Lennox fields in the Liverpool Bay Development and the changing economic climate, new support strategies were needed. P. 547

Abstract This paper provides the completion/drilling engineer with an innovative perspective on the technicalities of well abandonment and gives an insight into the first major well abandonment project in the UK sector of the North Sea. The paper discusses the planning and preparation of this novel approach to well abandonment. Details of the equipment utilized and an operational overview are also presented. Introduction One of the most interesting new challenges facing drilling/completion engineers in the North Sea is development well abandonment. As the North Sea becomes a mature oil province and as once prolific fields decline, operators are faced with the major project of field abandonment. These fields can have numerous wells producing from multiple horizons with variable degrees of well integrity. Specific well abandonment programmes must be developed for each well. Conventional well abandonment programmes, which can be very expensive, may not be the most technically appropriate. Detailed consideration must be given to each well to develop a technically sound and cost effective abandonment programme. During the first quarter of 1993 Hamilton Oil Company (HOC), on behalf of Hamilton Oil GB PLC, Hamilton Oil Pet Corp, LASMO (ULX) Ltd, Elf Exploration (UK) Plc, Texaco North Sea UK Ltd and Monument Resources Ltd abandoned 18 subsea completed wells on the Argyll Field Complex. A highly innovative programme was implemented involving the use of a multifunction dive support vessel (Stena Seawell) to perform subsea wireline, subsea cementing and tree/wellhead recovery. This work programme was successfully performed, cost effectively during the peak of winter without incident. FIELD SUMMARY Development Overview Discovered in Block 30/24 in 1971, the Argyll field became, in 1975, the first oilfield to be commercially produced in file North Sea. Initial production began from two subsea producers, in 260 ft water depth, tied back to a converted semi-submersible drilling rig - Transworld 58 (TW58). Crude oil was exported via a catenary anchor leg mooring buoy to tankers. In 1981 the Duncan field was discovered 3 miles to the West of Argyll. In 1984 the TW58 was replaced by another converted semi-submersible drilling rig - Deepsea Pioneer (DSP). The DSP included water injection and gas lift facilities. The Duncan field was tied back with 3 producers and two subsea water injectors and the Argyll wells were converted to subsea gas lift. This major re-development boosted production from 10,000 stbopd to 30,000 stbopd. In 1984 the small Innes reservoir was discovered 10 miles North West of Argyll. In 1985 the TW58 was located over Innes and production commenced from two Subsea producers with the crude oil being exported via a flowline to the DSP. Early in 1986 the TV58 was removed and production continued from the two subsea production wells via the Innes manifold to the DSP (Figure 1). Between 1986 and 1992 production gradually declined as the Innes reservoir depleted and watercut increased in Argyll and Duncan wells. A highly efficient operating philosophy maintained the profitability of the Argyll Complex until production declined to less than 6000 stbopd by mid 1992. Reservoir Overview The Argyll field has a highly faulted reservoir consisting of four productive horizons sandstone Jurassic, dolomitic Zechstein, sandstone Rotliegendes and sandstone Devonian The producing formations are at an approximate depth of 10000 it below sea level. The oil bearing reservoir intervals are underlain by a strong aquifer reservoir. On Argyll, despite continued production from gas lift wells for numerous years, the reservoir pressure stayed at approximately 3500 psi. Production decline was mainly the result of increased watercut, Watered-out layers were progressively shut-off and by the time the field was abandoned most wells were completed in a single productive zone. The Duncan field, a Jurassic sandstone reservoir, was developed with water injection. Reservoir pressure was maintained by seawater injection it approximately 4500 psi. The Innes field, a Rotliegendes sandstone reservoir, was produced with natural drive. By the time of field abandonment, reservoir pressure had declined to 2600 psi. Initial reservoir pressures and temperatures ranged from 5400 psi on Argyll to 6400 psi on Innes and 250 deg F on Argyll to 290 deg F on Innes. Total recovery from the three fields at the time of abandonment was 98 MMSTBO. Above the reservoir sands the fields are overlain by unproductive Cretaceous Chalk and thick deposits of Tertiary shares. P. 175^

Summary This paper describes the de-sign features of a surface lateral tree and compares the design with a conventional Christmas tree. A lateral Christmas tree is defined as a tree which has no valves in the vertical bore of the tree, and flow through the tree is controlled by valves on the lateral or horizontal bore of the tree. Preliminary evaluations indicate that the use of a surface lateral tree can enhance well intervention procedures, reduce wellhead/tree height, reduce maintenance requirements, and reduce overall risks. Introduction The use of lateral trees has been limited in the past. A type of lateral tree has been used on some land producing wells and several land based subsurface storage wells. For these installations, fluids are produced from and/or injected down an annulus through a side outlet in the casing head. Flow in the innermost bore or the tubing is generally controlled with conventional in-line valves. These applications are considered a combination of lateral and conventional configurations. The use of a true lateral tree in which all vertical in-line valves are omitted has been generally limited to low risk, artificially lifted wells. Recently, it was announced that lateral trees would be installed subsea as part of an upcoming North Sea development. The subsea lateral tree is expected to improve installation/workover procedures by eliminating the need for a complex workover equipment package. Overall, it is anticipated that the subsea lateral tree will offer advantages in cost operability and safety. Since some of the advantages of the subsea installation apply to surface installations, Phillips Petroleum Company United Kingdom Limited conducted an evaluation to determine the feasibility of using surface lateral trees on an offshore platform on an upcoming Central North Sea development project. At the present time, lateral trees have not been installed on an offshore platform well. Well intervention through conventional trees is sometimes difficult. It is necessary to establish reliable well bore barriers prior to installing a lubricator assembly for wireline work or to removing the tree to allow the installation of a blowout preventer (BOP) stack. Wells equipped with conventional trees have several undesirable features from both an operational and a safety point of view: The tree has to be removed prior to installing BOP's and pulling the downhole completion. It is necessary toestablish additional barriers in the well to carry out this operation. Generally, wireline plugs are set in the tubing and/or the tubing hanger. In some cases, the plug will not set and/or seal due to debris, corrosion or scale. When the additional barrier cannot be established using plugs, the tested barrier system may have to be compromised. In other cases, the plug becomes stuck during the time the plug is set, the tree is removed and the BOP's arc installed. Plugs are sometimes impossible to retrieve after installing the new completion and christmas tree. Setting and retrieving the plugs can be a time consuming and costly exercise.

Abstract The development of through-tubing retrievable bridge plugs suitable for the monobore type completions favoured in the North Sea provides a clear example of completion manufacturers fulfilling a need created by Operating Company requirements. The development and initial field application of a slickline retrievable bridge plug is described, illustrating the innovations inspired both by the Operating Companies technical leadership and the drive toward cost efficiency in well operations. The move by many North Sea Operators both in the United Kingdom and Norway towards monobore type completions has led to the development of a number of through tubing retrievable bridge plugs to complement the operations associated with these types of completions. This type of bridge plug quickly found applications in certain non-monobore type completions where the use of nipple profiles was not practical. The plugs initially developed for this type of application were deployed on electric line and set using explosive devices. Monobore completions, and more especially nippleless completions require the relatively frequent use of this type of Bridge plug. The requirement for electric line equipment and personnel naturally increases the operating cost of running these plugs. Since the oil price problems of 1986 Operators have been striving to reduce operating costs, and innovations to reduce the time and money spent on well operations are encouraged by the Operating Companies. The challenge therefore existed to develop a plug suitable for monobore type completions that was simple to use and cheap to operate. MONOBORE COMPLETIONS Monobore completions can generally be described as those where any restriction in the completion string is not smaller than the i.d. of the production liner. A more specific type of monobore completion is the nippleless completion where no profiles are included in the completion string other than in the tubing retrievable safety valve. An example of a monobore type completion is shown in Figure 1, and a nippleless completion string is illustrated in Figure 2. P. 33^

Permission to copy is restricted to an abstract of not more than 300 words. 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 paper will present the Tommeliten Subsea Development Project with emphasis on the X-mas tree and control systems. Project with emphasis on the X-mas tree and control systems. The experience from the test phase is also highlighted. The Subsea development of the Tommeliten field was interesting and special with regard to utilizing an existing platform system with a different operator/-owner for processing and distribution. It is also one of the first fields being developed with a 10,000 psi X-mas tree system. The trend of activities in the North Sea is towards smaller and less expensive development solutions. The field is marginal and was developed with an economically sound solution. 2. INTRODUCTION - THE FIELD Tommeliten, named after Tom Thumb, was put on stream 3rd October 1988, some twelve years after its discovery in 1976. The field is in fact the first discovery made by Statoil, the main oil company in Norway. Several concepts were considered but it was not until March 1986 that the development plan for Tommeliten phase one, based on a subsea solution, was submitted to the Norwegian authorities and approved in June the same year. In other words it took only about 24 months from tendering period to start up of production. The timescale for the project was driven by Statoil's downstream gas production commitments, and the short schedule demanded that the system should be as simple as possible without compromising the safety, performance and possible without compromising the safety, performance and availability of the system. The field is situated in the very south west part of the Norwegian continental shelf and consists of two separate gas accumulations 10 km apart in approximately 75 metres of water. For Tommeliten phase one, it is only one of these accumulations, the gamma phase one, it is only one of these accumulations, the gamma structure, which is being developed. The fluid contains 2.5 mol % CO2, and in combination with both high shut-in pressure of 5600 psi and high wellhead temperature of 226 degrees F, presenting challenges with respect to material selection presenting challenges with respect to material selection and corrosion protection. 3. PROJECT OVERVIEW The Tommeliten field is located 11 km away from the nearest installation, the Edda platform which is part of Ekofisk owned by a different operator. As the rate of production was decreasing on Edda, it was shown beneficial to utilize the surplus processing capacity as well as control the entire Tommeliten processing capacity as well as control the entire Tommeliten template from the Edda platform. This concept was therefore part of the plan for the Tommeliten development. part of the plan for the Tommeliten development. A 6-slot predrilling template was launched early 1987 in order to start drilling while the main template structure together with the trees and control systems were manufactured. During the drilling operations. a retrievable drilling guidebase which locked extremely to the 30" conductor housing was used. As this guidebase was retrievable, only one-off was required and it was moved from slot to slot during drilling. Later, the drilling guidebase was converted to a production guidebase and sufficient were manufactured to cover all the slots in the Template.