The Greater Plutonio development, deepwater offshore Angola, is BP's largest subsea development. The "soft" rock reservoirs require sand-control completions that are some of the most complex and challenging in the world. A commonly accepted view is that effective sand-control can result in sacrificing well productivity; however, the 23 wells completed to date have broken that paradigm with world class results and the largest well potentials in the history of BP.All twelve deepwater production wells employed Open Hole Gravel Pack completions, achieving outstanding results and technical limit productivity along with exceptional mechanical reliability and integrity. From the first well, they have all shown zero formation damage, resulting in individual well potentials up to 80 MBD. To support this prolific production capability, effective voidage replacement has been essential. Therefore, the injection well completions were designed to deliver equivalent well performance, while still providing robust sand-control. Based on this, Cased Hole Frac-Pack completions were selected for the initial gas and dual service injection wells with Stand-Alone Screen completions for the water injectors. The injector completions were as successfully deployed as their producer counterparts with technical limit injectivity on all the wells, setting a new standard for flow efficiency in high transmissibility reservoirs and delivering some of the largest water injector completions in BP's portfolio.The Greater Plutonio completions excellence story is one of a truly performance driven and innovative team. Productivity indices are up to four times greater than prognosed and mechanical skins in production wells are all zero (compared with +5 to +20 in analogous fields). This is underpinned by comparable injection performance and furthermore, the over 99% mechanical reliability and full data acquisition uptimes have substantially reduced the probability of costly well interventions in the future. This paper discusses the keys to the successful delivery of this world class completions performance and covers best practices and resultant well performance data of the first 23 wells from the planned initial 43 subsea well development.

Azeri-Chirag-Gunashli (ACG) is a giant field located in the Caspian Sea, Azerbaijan. The major reservoir zones are Pereriv sandstone formations with 20-25% porosity, permeability 100-1000md, and oil column up-to 1000m. These formations are weakly consolidated where Open Hole Gravel Pack (OHGP) completions have become the standard design for production wells. Development began in 1997 and to date more than 70 high rate (up to 45mbd per well) OHGPs have been installed.Wellbore stability issues require OHGP screens to be run in Oil Base Mud (OBM). Despite excellent initial success a number of sand control failures began to occur in 2008. A detailed gravel pack evaluation using multiple wash pipe gauges have revealed that earlier installations experienced screen plugging on lower section during the installation process. This leads to an incomplete pack in the toe area and subsequent screen failure as depletion increases or once water breakthrough occurs. The ultimate risk is of lost production rather than well control or loss of containment.Analysis was done to understand the root causes of screen plugging and to develop solutions for each. The work resulted in five key changes being made to the OHGP completions. o Revised TD criteria for the open hole section. o Modified OBM conditioning procedures. o Modified wellbore-clean-out procedures. o A modified screen BHA design. o The use of Ultra-Fine-Grain Barite in the OBM to reduce barite sag and the amount of large solids in the fluid system.These changes have resulted in less screen plugging, and hence increasing pack efficiency across the productive interval. This has resulted in a step change in OHGP reliability in the last 3 years with zero sand control failures over the last 24 completions. The detailed understanding of the failure mechanism also facilitated a successful intervention campaign to remediate several failed OHGP wells pre 2008. These efforts have delivered ~60mbd reduction in production losses over the past 2 years.

Ravenspurn North is a mature gas field forming part of BP's UKCS portfolio. The field commenced production in 1990 through 42 wells and 3 platforms but by 2006 half of the wells had ceased to flow. Surface pressures suggested limited remaining gas and, with declining production, the field was at risk of abandonment.A surveillance campaign carried out in 2006 suggested a common failure mode for many wells, which postulated that large amounts of proppant had accumulated in the wellbore. Pressures measured downhole above the proppant fill supported a significant increase of the remaining gas potential.A project to rejuvenate this field was initiated in 2007. The key to this project was cleaning out and reinstating non-flowing wells across the field. This would require pushing the boundaries of cleanout techniques and delivering a number of industry firsts, all on normally unmanned installations with complex logistical challenges. Additionally, each individual well intervention would be economically marginal on a standalone basis -the project had to place these interventions into a wider business context before building the case to justify the investment needed to resolve the many challenges presented. This paper details the journey to maximise the potential of the mature Ravenspurn North field. It starts with the acquisition of surveillance in 2006 and covers how the business case was built to justify one of BP's most complex well intervention programmes in the North Sea (concentric coiled tubing vacuum technology on a small unmanned platform). It culminates in the successful execution of the first phase of wells in 2010.With the first phase of the Ravenspurn North rejuvenation complete, this paper reflects on the lessons learned along the way and identifies the key activities which have contributed to delivering a longer, brighter future for this field.

Fibre-Optic Distributed Temperature Sensing (DTS) has been integrated into sand control completions in the giant Azeri Chirag Guneshli (ACG) field offshore Azerbaijan to provide real time production logging and assist with the management of the field’s complex reservoirs. The optimization of gas lift for better well performance, well integrity risk identification and the determination of gas and water breakthrough locations are some of the benefits that the DTS data has provided. Deployment of the fibre-optic system in the ACG field required a fiber-optic wet-mate and the ability to deploy fiber to distances up to 12km. Lessons learned from those deployments have yielded a number of best practices and design optimizations for the integrated completion system. These optimizations include hardware and software advancements, procedural changes for improved deployment reliability and the incorporation of critical pre-job checks at the vendor’s workshop prior to equipment load out to the rig. Maximizing reservoir potential and optimizing reservoir drainage is a critical part of the project economics for the ACG field and reliable sand control completions providing real time reservoir surveillance by means of DTS has proven to be a key technology for achieving this.

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