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Champion B.P.,Expro | Gandini G.,ENI S.p.A | Gabbiani A.,AREP STOGIT
Coiled Tubing and Well Intervention Conference and Exhibition 2010 | Year: 2010

There are many examples of wells around the world today that are shut-in due to failure of the Surface Controlled Sub-surface Safety Valve (SCSSV). Whilst these valves are generally very reliable, the control line that runs to surface in the annulus is susceptible to plugging by contaminants in the hydraulic control fluid and also to corrosion, which causes leaks; Both are outcomes that render the valve inoperable. The failure of the control line also means that the contingency solution of installing a Wireline Retrievable Surface Controlled Sub-surface Safety Valve (WR-SCSSV) is not possible. When a safety valve fails, the most common remedial solution today involves installing a Sub-surface Controlled Safety Valve (SSCSV), such as an ambient valve or storm choke. Whilst this solution is lower cost and more straightforward than performing a full rig-based well work over, it is not as safe. SSCSVs are directly influenced by changing well flow conditions, such as high flow rates, low pressures, or by water slugs, and thus are notoriously unpredictable in operation. Additionally, they are not controllable from surface and not fail-safe, which is undesirable from a well control and safety standpoint. By transmitting electromagnetic (EM) signals from surface to downhole, it is possible to control downhole hardware, A wireless controlled safety valve has been developed that can be retro-fitted into a well using conventional slickline intervention equipment and procedures. Being controllable from surface and of a fail-safe closed design, this valve offers both functional and safety advantages over existing SSCSV solutions. This new valve also offers a retro-fittable solution for wells having no hydraulic control line installed. In situations where a capillary string may need to be installed for foam or chemical injection purposes, it alsc provides an opportunity to free up the hydraulic control line. A prototype valve was subjected to qualification and functionality testing in accordance with a modified ISO 10432 test procedure. This testing was followed by installation in an onshore gas well for a 6 month trial that involved both flowing and injection phases. The valve was cycled and inflow-tested regularly and performed reliably, consistently and fully in accordance with specification throughout the trial period. This successful trial of a new wireless controlled safety valve marks the introduction of a more controllable and predictable aliemative to an ambient valve or storm choke, minimises deferred production and increases the well's safety. Following the successful onshore trial, the valve is now considered ready for wide scale field application onshore and at the time of writing this paper, plans for performing a first trial on an offshore platform are well advanced. Source


Expro initiated the the AX-S research and development program in 2003 with part-funding from three major operating companies to develop riserless system for cost-effective subsea well intervention. A feasibility study was completed in 2004, while design and testing of key components were performed. AX-S was designed to deliver a full range of wireline intervention services in deepwater wells at substantially less than the cost of using a rig. The system was deployed onto a subsea tree with an active heave-compensated fiber rope winch from a monohull vessel and remotely controlled from the surface as a remotely operated vehicle (ROV). It consisted of an integrated set of pressure-contained subsea packages comprising well control, wireline tools, wireline winch, and fluid management functions. An integrated hydraulic plug-pulling tool overcame the risks associated with pulling and setting tree crown plugs. Source


Law M.,Expro
Hart's E and P | Year: 2010

Expro has developed the AX-S system, to provide a safe, riserless, remotely operated subsea well intervention solution costing significantly less than a rig-based alternative. Various phases of AX-S project included conceptual development of the technology and solutions, detailed design and manufacturing, and dockside mobilization to be followed by ultimate installation on a selected vessel. The AX-S structure is 110 ft tall, weighs 220 metric tons, and is rated for operations to 10,000 ft water depth and 21,982 ft in-well depth. The structure consists of an integrated set of pressure-contained subsea packages comprising a well control package, tool storage package, wireline winch package, and fluid management package. Expro has also entered into an another multiyear charter party contract with TS Marine Asia Pacific to supply a vessel, ROV, and other associated services to support deployment of the system. Source


Law M.,Expro
Hart's E and P | Year: 2012

New ultra-deepwater riserless intervention technology is improving production at a fraction of the cost of traditional methods. While subsea well intervention is necessary, traditional methods can make it a time-consuming and very costly activity, with drilling and semisubmersible rig costs running from $1 million to $1.4 million a day. The sustained rise in deepwater exploration has made the challenge of cost-effective well intervention even more pertinent. The challenging conditions experienced at depth in Asia, Brazil, West Africa, and the Gulf of Mexico mean many wells have been producing for several years without necessary intervention. The AX-S subsea well intervention system is a life-of-field solution to well intervention and is designed to directly address some of the unique operating demands of the deepwater subsea environment. The system, which is deployed from a monohull vessel, is the world's first intervention technology that can operate in depths to 3,000 m, which means the technology is suitable for every subsea well in the world. Source


Champion B.P.,Expro
Society of Petroleum Engineers - SPE Bergen One Day Seminar | Year: 2016

Located in the Bjarmeland Platform area of the Barents Sea, Norvarg was discovered by Total in 2011 via wildcat well 7225/3-1, with gas being confirmed in both Jurassic and Triassic formations. A drill stem test (DST) was performed in the Triassic Upper Kobbe formation, but with non-commercial well productivity resulting. The post-DST vision for Norvarg was for stacked heterolithic tidal bar sands connected by large channel sands having better reservoir properties than tested in the first discovery well. The objectives of the follow-on Norvarg-2 appraisal well, drilled in 2013, included verifying the presence of the channel sands defined from seismic, quantifying the channel productivity and demonstrating the contribution of other Kobbe facies by performing an extended duration pressure buildup (PBU). It was a requirement that the selected PBU monitoring method would allow the well to be permanently abandoned in accordance with Norwegian legislation without any requirement for further well intervention. This was achieved by using an emergent new electromagnetic (EM) wireless reservoir monitoring technology, which allowed the pressure buildup to continue undisturbed beyond the end of the DST and final well abandonment. EM wireless monitoring technology is already well established as a means to monitor the reservoir pressure and temperature in abandoned appraisal wells, or suspended development wells, for the purpose of interference testing and reducing uncertainties in connectivity. However, this was the first time that it has been directly applied to monitor a long term PBU beyond final abandonment of a subsea appraisal well. By analysing the pressure transient data the objective was to investigate the presence of any flow barriers in the reservoir that might not be detectable during the course of a typical short duration pressure buildup performed during a DST. This paper presents a case study of the first time application in the Barents Sea of a post-abandonment wireless monitoring solution that successfully delivered high quality reservoir pressure and temperature data for a period of 9 months beyond the end of a DST. Analysis of the data provided clear evidence of internal flow barriers, located 130m and 280m from the wellbore, that were not observed during the normal DST period. This data proved the limited connected volumes and confirmed the requirement for additional development wells, compared with what was known prior to performing the test. This was important information to support the construction of the full field model and the further evaluation of the Norvarg prospect. Due to poor reservoir properties and disappointing deliverability, no viable development concept was identified for Norvarg, even with an increased well count and using fractured vertical and horizontal wells. The license for PL535 was subsequently relinquished in May 2014. Copyright 2016, Society of Petroleum Engineers. Source

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