Injection wells experience extremes of pressure and temperature as well as expansion and contraction during their normal operating cycles. This can cause numerous well integrity issues related to corrosion, leakage, degradation of barrier elements, operational practices that all put the health of the well at risk and require appropriate management. This paper will describe a case of a North Sea injection well that over time had developed sustained casing pressure (SCP) in the B-annulus. As a critical well in the development it was necessary to understand the origin and nature of the SCP as this would set further operational plans for the well helping to decide whether the well could continue to be operated safely, would require an intervention, or potentially will be abandoned. A leak investigation was needed to try to determine the source of the pressure, the type of fluid causing the pressure, the fluid path, and whether there was an injection out-of-zone as a result. To address all of the set objectives Distributed Fibre Optic (DFO) system was selected as a technology of choice. DFO provides an advantage over traditional leak detection methods through the ability to simultaneously monitor entire length of the well recording both acoustic and temperature profiles. Distributed Acoustic Sensing (DAS) was used to record acoustic signature of the well helping to determine the leak origin and likely pathway, while Distributed Temperature Sensing (DTS) was used to record well outflow profile and advise on possibility of out-of-zone injection. Use of pattern recognition techniques allowed to extract leak signature from background noise and other acoustic signals helping to pinpoint leak location. As a result of the application of DFO technology coupled with appropriate processing techniques way ahead for the well was identified providing an operator with a confident answer and saving on further intervention costs.

As the field matures and overall field production decline, an accelerated and advanced selection of existing wells for workovers and sidetracks would be critical to meet with the increasing demand for production. Traditionally, an intensive effort is required to identify the right candidates and to ensure the technical and economic success of well interventions, infill-drilling locations and sidetrack locations. An advanced workflow is developed to automate the repetitive and less added value tasks such as data gathering and validation. The data set included historical production performance, static and dynamic reservoir and fluid properties, events and issues encountered within the evaluated wells and regions. The proposed solution allowed an integrated assessment of production enhancement opportunities through various consistent analytic computations, as well as machine learning techniques including Bayesian networks and time-series forecasting models. The automated process generates a comprehensive list of future well interventions including sidetrack candidates, infill-drilling locations and behind casing opportunities with an advanced scoring system and several technical (production performance and reserves) and financial KPIs (i.e. net present value and unit technical cost). Several dashboards built and adjusted with the involvement of various company departments. Lastly, highly ranked opportunities are incorporated into the business plan in accordance to field development targets as well as the availability technical resources (rigs, materials, well availability). The developed solution was tested and validated in a giant mature carbonate field with over 700 well strings in Offshore Abu Dhabi. The solution identified 20 times more feasible opportunities than the typical multidisciplinary team review in 75% less time duration. The automated workflows considered re-evaluating and selecting prime candidates with a reduced risk of failure, therefore improving the technical and economic value by 34%. The workflows are scheduled on daily basis giving a time-dependent assessment and expert monitoring system, which can also notify the operator when problems encountered. Instead of computationally heavy traditional numerical simulation models, the assessment of a large number of well count can be done within hours instead of months. The combination of physics and machine learning based models lead to the development of automated workflows to rank and determine the best candidates via a successful cost optimization and production enhancement.

Near-wellbore diversion during acid fracturing or matrix acidizing is widely used to improve reservoir coverage and to save time spent on zonal isolation. It is particularly useful in offshore operations where efficiency is crucial. Diversion is typically achieved by dynamic placement of degradable solid particulates into perforations, wormholes, and/or fractures to divert the treatment fluid to understimulated zones. The diverting material must maintain integrity and mechanical strength during the operation before degrading at the downhole temperature in the presence of stimulation fluids. Whereas currently used materials work very well in a wide temperature range, at temperatures below 140°F (60°C), finding an appropriate diverting material that balances the trade-offs between surface shelf-life, stability during treatment, and fast downhole degradation is a challenge. This paper presents a novel low-temperature diverter that pushes the degradable diverter temperature limit down to 70°F (21°C). The new material was deployed in a matrix acidizing job performed on an injector well in the North Sea. Field deployment was preceded by an extensive laboratory testing program to verify diversion efficiency and acceptable degradation. The novel diverter was deployed in a restimulation treatment of a 10-year-old injection well where BHT was reduced to 70°F (21°C) due to long term injection of cold water. An acidizing treatment was designed to incorporate 4 diversion pills of the novel diversion material. All diversion pills were placed without extra operational time or operational issues. All four pills showed an instant pressure response of more than 250 psi as well as a sustained pressure increase of more than 100 psi, providing an indication of effective fluid diversion. The well was switched to injection mode less than 36 hours after the end of treatment without any flowback, providing a tremendous gain in operational efficiency. The post-treatment injection rate increased by 150% for several days, demonstrating significant and fast diverter degradation, despite the low temperature. The injection rate later stabilized at more than twice the pretreatment injectivity. The results demonstrate the viability of the novel low-temperature diverter in wells with BHT of 70 to 140°F (21 – 60 °C).

A multiphase compressor has been developed that provides: compression ratios up to 40:1, the ability to handle multiphase and slugging flow, and a very broad and flexible operating range allowing it to be positioned near the wellhead. Currently the product is targeted at onshore unconventional fields, and field data have been collected on such fields. For deployment to onshore unconventional fields the multiphase compressor has been packaged within a system so that it is easily transportable and fully self-contained, requiring no external power source or utilities. Also, minimal effort is required to tie in at the wellpad (just process connections in and out), no downhole intervention is needed, and typically no site preparations are required, which allow it to be easily relocatable with minimal sunk investment cost. Onshore applications include: Artificial lift from surface to increase production and reserves, and reduce operating costs – applicable to both oil wells with moderate quantities of gas present, and gas wells suffering from liquid loading. Field data show production enhancement of up to 300% versus alternative forms of artificial lift. ‘Frac hit’ recovery to restore parent well production more quickly (by accelerated recovery of preload or ‘frac hit’ fluids from parent wells) – applicable to both oil and gas wells. Field data show accelerated fluid removal versus alternative forms of artificial lift and reservoir studies indicate around an order of magnitude faster recovery of fluids. Lower methane and CO 2 emissions and operating costs from field operations – operator intensive flowbacks to open top tanks to kick wells off can instead be achieved with the multiphase compressor, which also avoids the methane emissions to the environment associated with open top tank flowbacks or CO 2 emissions from flaring. Lower methane and CO 2 emission field development options – by enabling multiphase gathering to centralized facilities, the emissions associated with poor pad separation and the associated fugitive emissions from on-site storage and movement of volatile liquids can be eliminated, and at the same time eliminating operating costs associated with intensive distributed operations such as road tanker export of oil from wellpads. Additionally, abandonment of late life conventional oil and gas reservoirs and wells can be deferred by avoiding slugging well flows for longer – adding both production and reserves, and removing the operating cost associated with kicking off wells. For land conventional well applications the same multiphase compressor and package can be deployed as for unconventional fields – and the system packaging can be easily adjusted to deploy to offshore platforms. The multiphase compressor has also been redesigned for subsea, and uses the same principles of operation to provide unique benefits for subsea applications: particularly for late life gas wells to add more production and reserves than would be possible from existing subsea multiphase boosting. Operators will be able to deliver more production and reserves from their existing assets, reduce operating costs, and lower environmental emissions from their production operations.

Fast-track engineering to expeditiously deploy new technologies in upstream oil and gas heavily relies on timely agreement and synergy between the engineering team and stakeholders on (1) tool architecture (2) operational envelope and wellbore environment (3) qualification criteria(s) and overall verification & validation (V&V) strategy, among others which lead to the product specifications. Here we present a "Case Study" where two new technologies, were engineered to order for the Middle East and North Africa (MENA) regions: a first-generation Pressure-Temperature (P-T) flowable sensor from our "Teleo" product line, and a multilayered water reactive plug for multi-stage stimulation (MSS) and acid frac, designed from bulk ultrafine-grained light alloys and water reactive, nanocomposites.

A major concern in offshore production is the well intervention cost and the time taken to perform the operations. These issues relate to the need for a rig or a similar unit to perform those operations. This paper presents the current stage of the development of an autonomous robot for rigless well interventions. The robot enters the well through the Christmas Tree using a special tool. This proposal will allow significant cost reduction by avoiding the need for a rig to do light workover operations in offshore locations. This strategy reduces intervention time since a simpler unit may deploy the robot. Examples of operation performed by the robot are production logging, gas lift valve replacement, sliding sleeve opening and closing and plug insertion or removal. A Simplified Robot allowed evaluating the technical feasibility of this proposal, both theoretically and experimentally. This Simplified Robot allowed evaluating the Traction System, the Energy Storage, and the Positioning Algorithm. After that, the design of the Real Robot started. This system will be modular and adjustable according to the needed operation.

This paper discusses a cost-reducing technology that has been used globally in multiple well construction and abandonment applications. The electromechanical remotely operated barrier valve is designed to maximize operational efficiencies and create savings by decreasing valuable rig time from applications. The remote-control operation is facilitated by preprogrammed pressure and timer sequences and is easily tailored to the well conditions and tasks to be performed. This paper discusses field data from applications where the technology has been used and the value created in each case. The remotely operated barrier valve has been deployed in multiple applications, including completion deployment, well suspension, zonal isolation, decommissioning, and as a replacement for ball-drop valves. The valve uses onboard decision-making electronics and is a retrievable, computer-controlled ball valve that can be repeatedly opened and closed by remote command. No connections to the surface or well interventions are necessary to communicate with and operate the valve. The valve is predominantly deployed below a lock mandrel or retrievable bridge plug. With each function of the valve, an intervention is eliminated from the operation, dramatically reducing rig time and the associated operational and health, safety, and environmental (HSE) risks. The first field installation for the remotely operated barrier valve was in February 2008 for an operator in the Norwegian sector of the North Sea; since then, the valve has been used on more than 600 installations by 40 separate operators in greater than 20 countries. With approximately 1,400 remote activations to date, it has effectively reduced well intervention costs whilst reducing the operational and HSE risks associated with these operations. Well construction efficiencies and cost savings remain a top priority in an industry where the challenge is no longer to maximize production but to reduce production costs and operational expenditures (OPEX) because of lower oil prices. The use of remotely operated barrier valves has been successfully addressing this challenge for the last decade.

Subsea Pumping Well Intervention Systems (SPWISs) include a reeled fluid conduit (or riser) that connects a surface pumping spread to a subsea tree via a subsea safety module. Current pipe technologies used for fluid conduits are limited in terms of their pressure capability, volume of fluid they can supply, fatigue performance or the ease with which they can be deployed. Thermoplastic Composite Pipe (TCP) addresses many of the limitations of existing products, and therefore is attractive as an alternative. This paper describes the qualification of a TCP as a SPWIS fluid conduit. The TCP is manufactured from carbon and S2-glass fibre, laminated with a Poly Ether Etherketone (PEEK) matrix. The TCP was qualified following the processes recommended by DNV-RP-A203 "Qualification of New Technology" and the specific guidance given in DNVGL-RP-F119 "Recommended Practice for TCPs". The former defines a structured process for developing a qualification basis, assessing the risk of all potential product failure modes, and then mitigating those risks through the collection of qualification evidence. The latter provides a methodology based upon a testing pyramid and a linked structural model, to gather the appropriate qualification evidence for a TCP. The results of the TCP qualification are presented in three areas, materials testing, pipe testing and structural analysis. The material testing focussed on characterising both pure PEEK, and the properties of individual carbon and S2-glass plies in the composite laminate. Testing was performed across the design temperature range (4°C to 80°C), and was used as input into the structural model of the TCP that was developed. At a pipe scale a comprehensive set of single and combined static load cases were tested, including axial tension and compression, internal pressure, bending, and bending and internal pressure. These test results were compared against the predicted TCP performance given by the structural model, both in terms of stiffness and ultimate failure. In addition to the static testing, long term performance of the composite laminate was also characterised. Laminate testing methods were developed for fatigue and stress rupture, and the test results used to construct life curves for both failure modes. The combination of both the materials and pipe testing, and the structural analysis, culminated in a qualification certificate being issued for the TCP by an Independent Verification Agent. DNVGL-RP-F119 is a new recommended practice that was published in December 2015. This paper presents one of the first applications of the recommended practice to a TCP product, and therefore provides valuable insight into the practical implementation of DNVGL-RP-F119. In addition, qualification of a TCP as a SPWIS fluid conduit offers the potential to enable more frequent and effective well interventions, thereby improving the productivity and ultimately reducing the cost of subsea wells.

Well barrier installation practice is dictated by territoryspecific regulations which are largely based on historic practices. However, emerging technologies, tighteningnationalregulations, and demands from assetowners are gradually affecting the way we carry out our intervention operations. Driving the technology development is time saving but with a sharp eye on safety. Well documented verifications on temporary barriers and barriers installed for well suspension and future P&A barrier installation is expected. There are multiple issues involved in gaining proper verification of aninstalled barrier. One major issue appearing is the general condition and status of previously installed plugs and valve components in older wells, which canresult intwo wellbore barriers installed in close proximity. Othermajor issues are the well'sgeneral ability to support an inflow test, and the time it takes to get asegregating well stable.

The challenge faced when identifying and planning the requirement for intervention and workover operations on small platforms or single caissons is significant. Typically drilled via a jack up rig, there are limited opportunities to install hardware to the platform directly. With an increasing well stock reaching maturity, there is a requirement to perform operations at a reduced cost on wells with increasing deviation and complexity. This scenario would typically be addressed by a jack up rig being installed over the well site, or with a HWU (Hydraulic Workover Unit) being installed if there are capping beams/availability to install them. Each has its merits; however, they also have cost and safety implications respectively. To address the market of platforms with limited structural capacity, a new WHWOU (Wellhead Mounted Workover Unit) has been developed to facilitate intervention, workover and abandonment operations in a safe and efficient manner on platforms with structural limitations. This paper describes the market challenges facing mature basins and assesses the opportunities arising to perform intervention and workover operations on the ageing well stock to stimulate well production. It also presents key design parameters driving the new technology, principally: Safety, Efficiency and Cost reductions. Each is achieved through lessons learned allied with a novel approach to the use of new technology. Operational flexibility facilitates wireline, coiled tubing, pumping and fishing operations for example to aid wellbore stimulation activities. It also facilitates heavy workover such as re-completion, re-perforation, and whipstock setting in preparation for multilateral well development. Plugging and Abandonment operations are achievable with section milling, primary isolation plug setting, and tubular recovery through the design. The operational capability is supplemented by a flexible philosophy - deployment through appropriate well control equipment to the surface wellhead. Further, the ability to be installed on light beams or by cantilever beams from a lift barge or boat gives the end client numerous scenarios for a campaign and platform stock. The WHWOU will allow operators to successfully conduct operations on a wide range of platforms from single wells to downgraded structures with multiple well slots and active process facilities.

Acid stimulation and scale squeezing are generally well-established hydraulic well intervention practices, although methods for delivering such treatments specifically to deepwater, subsea wells are a less mature area of application. A rig-less intervention alternative provides a more economic option for intervening on subsea wells, in comparison to traditional rig-based methods. This technical paper describes the planning and execution of a multi-service vessel (MSV)-based hydraulic intervention campaign at Chevron's Tahiti field in the U.S. Gulf of Mexico. Challenged with early-life well productivity decline and imminent injected seawater breakthrough, the Tahiti asset formed a multi-disciplinary team to develop a fit-for-purpose solution to remediate and mitigate these concerns. Acid stimulation was selected to arrest and recover well productivity, while scale squeezing was required for protection against barium sulfate scaling from the mixing of formation water and injected seawater. These treatments were to be delivered to subsea production wells in water depths of ~4,200 ft. The design basis of this hydraulic intervention system involved dual, open-water coiled tubing strings deployed from the MSV to a subsea stimulation module. This module is landed and secured subsea on a modified suction pile, allowing structural isolation from the horizontal subsea production trees. In turn, a flexible jumper from this module to a valve package and modified choke insert on the tree enabled access to the wellbore for delivery of the treatments. De-coupling the stimulation module from the tree interface alleviated the risk and complexity of removing crown plugs and imparting load forces on the tree, and denotes the ‘hybrid’ nature of the system. Design and operational phases required overcoming challenges such as coiled tubing fatigue management, unexpected loop current conditions, and deployment sequence optimization. Given the first-time deployment of this hybrid system, detailed front-end engineering and design was required for validation of an enhanced well control and emergency disconnect system, to accommodate safe execution. The 5-well campaign was executed incident-free during 2015, delivering a total treatment volume of almost 30,000 bbls, resulting in 8,500 BOPD gross initial production uplift, and cost savings of 85% in comparison to traditional rig-based methods.

The development of innovative technologies and the effective application of late-stage intervention and abandonment systems in the oil and gas industry have resulted in cost savings and an increased standard of safety. This paper examines the successes of fit-for-purpose systems specifically designed for operations on load bearing offshore platform projects in an efficient manner. To effectively address the market, a new system for completing interventions and abandonment operations was needed. Subsequently, a system was designed which incorporates capabilities associated with Jack Up rigs along with the quick mobilization and set up of a crane assisted rigless unit. This solution has been utilized in offshore campaigns that include all phases of abandonment operations including well diagnostics, reservoir isolation, tubular retrieval, fishing and section milling. This paper will review the capabilities of the system along with case studies which highlight the versatility and adaptability of the system which provides an integrated solution package to the client. The system which includes a Pulling and Jacking unit also incorporates all ancillary equipment necessary to proficiently intervene and permanently abandon offshore wells. These case studies will discuss the planned parameters, examine the operations, and review the lessons learned from the projects.

The area West of Shetland (WoS) between the UK and Faroe Islands, also known as the Atlantic Frontier, is characterized by a harsh environment with strong currents, presenting significant challenges for offshore operations. Our experience in this area began for the first time in 2009, performing Riserless Light Well Intervention (RLWI) operations. This type of well intervention had never been performed in this area and the challenge showed to be far bigger than first anticipated. This is the seventh season with RLWI operations West of Shetland, an environment which is known to be very challenging due to extreme ocean currents. The first season there were significant struggles with the difficult environmental conditions. Strong currents caused damages to both RLWI equipment and vessel, forcing the operation to be stopped. To be able to complete the operations a quick adaption to this demanding environment was needed. The organization managed to turn around quickly and do the needed modification to respond to the challenging environment, making it possible to complete the operations in this harsh environment. After a steep learning curve and 6 years operational experience in this area, the operations are now completed ahead of schedule. This paper will discuss the challenges experienced performing RLWI operations West of Shetland. Damages to equipment caused by the harsh environment and the “battle” to overcome these challenges will be discussed.

Abstract Slickline often plays a vital role in offshore plug and abandonment (P&A) operations, either used in the phases of the operation that require slickline conveyance, or because logistical, footprint, operational, economical, environmental or regulatory parameters of a P&A operation necessitate full reliance on this small, light, cost-effective conveyance offering. Today's evolving regulatory requirements are leading to an increasing demand on the scheduling and design of P&A activities. For activities such as barrier placement, proof that the work is being carried out to the prescribed high quality is increasingly required both by the operators and the authorities. In addition, as the time, costs, and risks involved in carrying out an offshore P&A operation are considerable, possible savings and risk reduction are highly sought after by the customer. P&A activities such as perforation, punching, cutting, device setting, and cement placement, previously done by electric line or with memory-based tools which required additional runs in the well and provided only post-job QC, can be carried out by digital slickline without any compromise to the efficiency and immediate certainty of the operation. Conducting these P&A activities with digital slickline enables efficiencies through equipment and logistics simplification, and people and equipment rationalization, as well as reductions in marine support requirements. Time and cost savings and process risk reduction or elimination, important in their own right on a single well abandonment operation, are increasingly relevant when applied on a full field abandonment scope of work. In addition, the suitability of slickline conveyance in such environments as riserless intervention P&A operations (negating the need for grease injection pressure seal), is another important feature that is part-and-parcel of a digital slickline operation. This paper will demonstrate, through actual field examples, the use of digital slickline's inherent surface read out and command and control capabilities, the operational value of precision and clarity delivered in real time, and the specific P&A job recordability and capabilities that have been absent from slickline operations of past. Also highlighted are digital slickline's facilitation of personnel and equipment reduction, and subsequent reduction in HSE exposure.

Abstract As the number of wells that need to be plugged & abandoned grows so do the applications for uses of inflatable packers. This paper will discuss common applications and practical uses for inflatable packers in past, current, and in future wells in the Gulf of Mexico, USA. Inflatable packers are proving to be valuable tools to assist directly with stopping annular gas migration, performing mandatory cement testing, casing leak detection, and cement squeeze applications during the plug and abandonment (P&A) process. Inflatable packer versatility is proving to provide a wide range of setting options that allow the ever changing P&A environment the ability to use single tool configurations for multiple applications. This tool adaptability reduces spread cost through down time reduction. Processes and the use of a peer review approach ensures that the latest techniques and practices are utilized and reviewed to incorporate the safest, effective, and most economical methods for well abandonment. These specific inflatable packer applications will be shown through multiple case histories, where exact well parameters will be discussed, showing the results of each particular job. These case histories will discuss and illustrate temporary well abandonment, permanent well abandonment, re-abandonment, subsea well abandonment, and/or rigless abandonments. Introduction Inflatable packers have increasingly gained popularity in the last decades due to their proven reliability, performance and flexibility. There is significant use in different applications from zonal isolation to plug and abandonment operations due to casing restrictions, non standard casing, damaged casing or when conventional mechanical packers or plugs are not an option. They could be either retrievable or permanent and have been used as: Cement Retainers Bridge Plug Cemented Packer Multi-Set Squeeze Packer Multi-Set Test Packer Deployment methods vary from wireline (E-line or Slickline), drill pipe, coiled tubing, Cat line or crane on the production platform where work space is limited.

Abstract In recent years, the number of subsea wells has increased steadily; a 2011 report estimated more than 5,500 worldwide. One of the key challenges the industry faces with subsea wells is generally lower recovery factors compared to wells with surface access. A key reason for this difference is because workover activities to improve recovery rates in subsea wells has traditionally required use of large rigs, risers, jointed pipe or coiled tubing (CT), with high operating rates. The high costs of these operations can make it difficult to achieve the necessary increases in production rates and revenue to justify the workover investment, even with increasing oil prices; therefore, operators often forgo production-improvement workovers. However, a growing global population and soaring energy demand means that operators are facing increasing pressure to maximize production and value from mature assets. These challenges have spurred development of alternative, lighter weight, more cost-effective intervention methods to enhance recovery rates in deepwater, subsurface wells. These alternative technologies include electric-line tools that can be run from smaller, dynamically positioned light well intervention vessels, instead of large workover ships with risers. These rigless and riserless light well interventions (RLWI) improve scheduling flexibility and reduce costs, thereby reducing barriers to performing subsurface well interventions and enabling subsea operators to realize oil recovery rates of 50% or more. Today many industry companies have a clear tendency to migrate towards lightweight, more cost-effective alternative solutions. But for some, misperceptions still exist and skepticism remains for using RLWI for deepwater subsea wells. However, over the past decade, RLWI has achieved a solid track record of demonstrated value and is an inherently safer method for subsea well interventions, compared to conventional heavier methods. This paper describes the opportunities to improve recovery rates in subsea wells using the lighter, more efficient and ultimately more productive RLWI methods. Using these techniques has enabled operators to conduct routine planned access to subsea producing assets, improve surveillance and management of interventions, and, ultimately, increase recovery rates. Several case histories and examples are presented. Introduction Challenge: The Need to Increase Production from Existing Assets to Meet Growing Global Demand for Energy. Looking at peak oil production from a number of the major oil producers shows that many of them have reached peak oil production over the last ten years (Table 1) the industry is striving to find new resources to replace diminishing reserves and to meet increasing global demand; these factors are moving exploration and development into deeper water offshore, where currently more new fields are being developed subsea than from platforms (Strategic Offshore Research Ltd. 2012).

Abstract The need for cost effective subsea well intervention has been discussed and documented over the last few years. Both the increasing number of installed subsea wells combined with the increasing age of subsea fields continues to drive demand for more efficient subsea well intervention. The team at Blue Ocean Technologies has been providing innovative solutions for various types of subsea well intervention for the past four years. This paper discusses some of the technology challenges Blue Ocean Technologies has overcome and some of the best practices we have developed in order to provide safe, reliable and efficient riserless subsea well intervention. Background Riserless subsea well intervention is becoming a more widely used and familiar technique with various wells around the world being worked on without a riser over the last years. The pressure to work without a riser has brought riserless intervention into the mainstream, driven by deepwater rig costs and availability although the work to remediate wells downed by hurricanes in the last five years, from Ivan to Ike, has also acted as a catalyst in getting operators interested in, and the necessary investment to develop the technique. What is new in riserless well intervention is that we are now working in deeper water and facing and solving the associated challenges. With these advances in technology, depth, capability, and complexity of operations is increasing. As operators have developed deep water prospects going through the 5000' depth barrier in 1997 and through 9000' in 2006, the need for cost effective ways to intervene has grown. Deep water well completion technology enables wells to be completed with a view to less intervention but as the fields mature and energy prices fluctuate, increasing recovery, and reducing abandonment costs have become more important. Several operators have shown interest in investing in the necessary technology but most have been driven by the need to complete the fields with the lowest capital expenditure and hand over to their production groups to do the rest. Accepting that fact, the work done to remediate downed wells has served to increase operator interest and although we would make the case that no real breakthrough technology was developed in these shelf/shallow water projects, the application of technology to the problem and the experience gained in that work increased operator comfort levels in use of riserless intervention. Blue Ocean also grew through experience gained in remediation of downed wells evolving over the last few years to provide deeper water subsea intervention capabilities. The initial push was to plug and abandon wells less expensively by using DP vessels, freeing up rigs to drill exploration and production wells. This push developed into production intervention projects to improve recovery of hydrocarbons from these deeper water subsea wells. Riserless intervention has " come of age?? with routine interventions at 3000' water depth and deeper depths planned. Challenges Amongst challenges in riserless intervention is maintaining an effective and reliable seal against the wellbore pressure. In shallower water depths, approximately eight hundred feet or less, this can be done with slightly modified land systems, with elastomer sealing elements if slick line is to be deployed through the lubricator. This was predominantly the method used for the downed wells, the majority of which were in water depths under eight hundred feet, and for which slickline could provide the necessary wire line capability.

Abstract With the growing number of ageing subsea wells in the North Sea needing some sort of intervention, the demand for efficient subsea light well intervention service continues to grow. Such service has been in operation in the Norwegian sector for the past six years and is currently experiencing exponential growth with the addition of several more intervention systems spurred by continued long term commitments. This paper presents a review of performance gains from second generation riserless light well intervention (RLWI) equipment currently working in the North Sea, focusing on the performance gains in-water umbilical management, safer deck handling, efficiency from remote in-situ fluid delivery, and hydrate control. Improved well control " barrier?? equipment now accommodates 1/3 longer length wireline tools, electric-powered control system architecture using ROV-type control cable (umbilical), autonomous grease injection capability, subsea monitored chemical injection and fluid exchange/ flushing capabilities have reduced fluid wastage and contingency tankage requirements; all introduced from recommendations and lessons learned from first generation RLWI systems Introduction Riserless Light Well Intervention (RLWI) has now established itself as a field-proven method for wireline intervention in subsea wells. Regular operations since 2006 from monohulls have shown great results on the production and recovery side and, now with two more systems coming on stream last season, a statistically significant number of well interventions have been performed. It is therefore now possible to establish reliable cost and time estimates for the potential well interventions being planned. This paper discusses the experiences gained from these operations. Review of functionality upgrades Mark II After several years of operation with the first system, market demand for more systems triggered the development of what became the Mark II system. Overall principles from the first generation were maintained for well barriers and overall system philosophy. However, to improve operational efficiencies, the control system architecture was updated, mitigating the possibilities of time lost due to handling of the large diameter IWOCS electro-hydraulic umbilical. The approach taken being to remove on-deck based surface power generation equipment and replaces the maze of hydraulic hoses and fittings associated with the cumbersome IWOCS umbilical with a ROV type fiber optic-electrical control cable. The subsea IWOCS controls powered by the cable features the same distributed control architecture found on newer work class ROVs, taking advantage of IP routing and control. As it was expected that deepwater markets also would look for RLWI services as wells mature, the Mark II system was also prepared for easy adaptation for deepwater operations to water depths of 3000 m (10 000 ft) at a later stage. A thorough discussion of the Mark II system and its upgraded features has been presented in earlier OTC papers [3, 4].

Abstract Island Offshore has since 2005 been operating riserless well intervention units in the North Sea. The first unit has successfully performed more than 50 well interventions since start April 2005. Another two units have been put into operation in 2009. Both are purpose built based on experiences gathered from the first unit. The paper will discuss the operating experiences from the first years and how these experiences have influenced two second generation well intervention units.. Further, the presentation will also discuss challenges for this type of service as well as future opportunities Introduction Currently there are more than 5000 subsea wells world wide and the number is growing, particular in areas like West Africa and Brazil. In the North Sea there are approx. 1300 subsea wells of which about 500 are located on the Norwegian Continental shelf (NCS). The intervention frequency on subsea completed wells should in theory not deviate substantially from platform wells. Platform wells on average experience an intervention every 4th year, while subsea wells more rarely are being maintained. There is a significant discrepancy between UOR (ultimate oil recovery) for platform wells vs. subsea completed wells; as from subsea wells UOR < 35%, platforms wells experience >50% UOR (some fields > than 70%, North Sea - Statfjord). On the Norwegian sector of the North Sea, Statoil during 2009 did totally 25 well interventions utilizing two specialized units for RLWI. The cost benefit by these operations, according to the operator, did result in a net profit of approx. $ 2,5 billion. During 2010, approx. 40 well interventions are scheduled utilizing the same units, while a third unit will be operating on the UKCS, West of Shetlands, (WoS) extending the operation to even harsher environment. The Units During 2009, two of the units, (Island Frontier and Island Wellserver), have been operating on the NCS, while the third unit Island Constructor, has been operating mainly on the UKCS, WoS.

Abstract A prolific gas-condensate well in the Caspian Sea was forced to shut in due to a leak in a premium connection of the 7 in. production tubing resulting in loss of well integrity. Immediate repair was required to re-establish production. An expandable tubing patch (solid expandable cased-hole liner) was selected to provide a high-pressure, gas-tight, and potentially long-term repair of the leak while minimizing the loss of wellbore internal diameter (ID). In a very short time frame, engineering teams successfully collaborated to design, manufacture, and qualify the expandable tubing patch to a V0 (zero-bubble acceptance criterion) test protocol. The tubing patch was successfully installed without killing the well using a single downhole barrier and a snubbing unit. The well was returned to production in May 2007, and has been on continuous production without any evidence of a re-occurrence of the tubing leak. This paper will review the well engineering, design engineering, qualification testing, QA/QC, and operational installation planning. Close teamwork between the end user and the expandable provider resulted in the successful repair of the well and allowed the operator to progress the return of the well to service. Introduction The Shah Deniz field, confirmed in 1999, is a giant high-pressure gas condensate field containing approximately 30 TCF of gas and a significant amount of condensate offshore Azerbaijan in the Caspian Sea (Figure 1). Shah Deniz Stage 1 sanctioned 12 wells with further development planned in the field with a life estimated to more than 30 years. Well conditions are near HPHT with a reservoir pressure of 12,500 psi at 20,000 ft (~6,100m) TVD and a static reservoir temperature of 212°F. Drilling and production occur from the Shah Deniz Alpha (SDA) platform in water depth ~330 ft (~100m) (Figure 2). Licensees and subsequent interests in the Shah Deniz Exploration, Development, and Production Sharing Agreement (EDPSA) include the following: BP, operator - 25.5% StatoilHydro - 25.5% State Oil Company of the Azerbaijan Republic (SOCAR) - 10% LUKoil - 10% Nico - 10% Total - 10% TPAO - 9% Wells producing from the Shah Deniz field are among the most prolific in BP's global portfolio. As such, the integrity of these wells is essential to the company's strategy for exporting gas from the Caspian Sea.