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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.

Gary B.,Halliburton Co. | Hosli C.,Royal Dutch Shell | Luviano A.,Welltec | Langley J.,Expro
Society of Petroleum Engineers - Coiled Tubing and Well Intervention Conference and Exhibition 2014 | Year: 2014

A requirement1 within a conventional offshore well's completion design per operator standard design and/or governmental regulation2 is the installation of a "subsurface safety device." Among the list of permitted safety devices, subsurface safety valves (SSVs), if maintained properly, can fulfill such a requirement in well control and isolation. Whether it is of the surface-controlled (SC), subsurface-controlled (SSC), wireline-retrievable (WR), tubing-retrievable (TR), ball check, or flapper valve variety, subsurface safety valves can easily be damaged during through-tubing (wireline, coiled tubing [CT], etc.) deployment through the valve if steps, such as equalization before opening, slowing toolstring running speed, etc., are not taken to properly safeguard valve integrity. A problem that could occur during these deployments, specifically in reference to the SSV flapper-type valve, is shearing of the hinge pin on which the valve flapper rotates, allowing the flapper to "float" in a cavity directly below its rotation point, creating an effective downhole obstruction. A traditional intervention operation to repair this includes using a slickline (SL) rotating wedge to manipulate the flapper to a position that will allow a subsequent, suitably3 sized sleeve installation through the cavity, bypassing the flapper. This will allow for both toolstring deployment past the obstruction to assist in future uphole recompletion operations and continued production without slugging from unexpected valve flapper reseating. This paper discusses a case history in which the above-mentioned conventional SL manipulation toolstring was deemed not suitable, as it was currently designed for a small cavity-type Tubing Retrievable Surface Controlled Subsurface Safety Valve (TRSCSSV), and alternative intervention means were developed. Five full-scale4 tests were performed with four different toolstrings (one SL and three electric line [EL]) engineered to provide a method of inserting a bypass sleeve with predetermined minimum inside diameter requirements for future tubing cutter deployment. Of the four toolstring options developed, two were deemed field ready and deployed with the offshore operation itself, while the other two required additional engineered modifications. Details of the successful intervention deployment are also given in which desired flapper orientation and isolation was not only achieved by toolstring manipulation but also by well-production characteristics. Three benefits can instantly be noted from the developments and lessons learned. First, the toolstring solutions could be used for obstruction isolation of many varieties. Second, this rigless operation is part of the ongoing efforts in the Gulf of Mexico and elsewhere in the world to intervene in wells in the most economically feasible, least hazardous, and most expedited manner. Lastly, the intervention means employed here incorporates toolstring components readily available on the market. Lead time and operational use are minimized, and rig campaign schedules can be maintained almost without delay. Copyright 2014, Society of Petroleum Engineers.

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.

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.

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.

Pedroso C.A.,QGEP | Monteiro G.G.,QGEP | Marsili M.D.,QGEP | Liborio F.,QGEP | And 2 more authors.
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2015

Testing heavy oil in offshore wells is, by itself, a challenge. But testing heavy oil, highly viscous (220 cP at the reservoir temperature), in ultradeep waters (1550 m), in a horizontal well equipped with a long open hole horizontal gravel pack (800m), using an electrical submersible pump (ESP) deployed in a slant section at 75 degrees is really a big challenge. Atlanta is a post-salt oil field located 185 km off the coast of Rio de Janeiro. The field was discovered in 2001. The appraisal plan, started at the same year, included a deviated well to test the eocenic sandstones. A cased hole gravel pack was installed. The 90m interval tested, showed an unconsolidated sandstone, with high porosity (35%) and high permeability (5D). However, the oil is heavy and viscous (14° API and 228 cP in reservoir conditions), very acidic (TAN=9.8). In 2006, a long horizontal well was drilled to validate the field development concept and evaluate the potential of this kind of well construction. However, crucial problems were faced in the drilling and completion phase, which included, directional control problems, massive fluid loss in the reservoir section, use of a LCM pill, premature screen during the open hole gravel pack operation, leaving a SAS completion. Even after these problems, it was decided to maintain the well test. An ESP was run in the DST string. After some flow (approximately 20 h), the screens were plugged resulting in their failure and therefore sand/solid production. The ESP locked with the produced solids and overheated, getting burned. The partially conclusive DST showed a severe damaged well, with high skin of 40. The well was abandoned without carrying out its objectives, and the horizontal completion was not fully evaluated. The bad experience compromised the reliability of the project. However, in 2012, another operator decided to revisit the lower completion and testing procedures. After considering technology improvements and the lessons learned in the past operations, an extensive testing program was stablished and carefully executed. In 2013 a well was drilled, completed and successfully tested, with the ESP near the top of the reservoir. The zero skin completion and high productivity of the well encouraged the operator to drill and test the second well, this time using the ESP above the sea bed, inside the drilling riser, which included more difficulties due to the low temperature at that position. This paper presents the main challenges and details on how they were overcome by the successful completion and testing of the first two production wells encouraging to move on to the next phase. © Copyright 2015, Society of Petroleum Engineers.

Champion B.P.,Expro | Puntel E.A.,Petrobras
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2015

Uncertainties in reservoir connectivity and compartmentalization risk are important considerations when thinking about any new field appraisal or development options. Having a better understanding of reservoir connectivity provides benefits in determining the appropriate drainage strategy and optimizing the field development plan. By the application of a new wireless reservoir monitoring technology, based on electromagnetic (EM) communications, it is now possible to monitor the reservoir pressure and temperature response during the long term suspension of development or appraisal wells. Accurate reservoir data can now be reliably collected in the period prior to a completion string being run, or a Xmas tree being installed on the well. Petrobras is conducting an active programme of drilling and well testing evaluation in the Pre-Salt Santos Basin area, with the objective of maximizing the collection of reservoir data that can be used to prove the reservoir models. An opportunity was identified to utilize this wireless monitoring technology in some newly drilled development wells that were to be suspended for an extended period of up to 3 years. The primary monitoring objective was to gather dynamic reservoir pressure data that could be used to identify interference effects resulting from production or injection events in the adjacent field area. Any evidence of interference will serve to prove reservoir connectivity with the adjacent well assets. A secondary monitoring objective was to record a long term pressure build-up, beyond the end of a Drill Stem Test (DST), to check for the presence of any reservoir boundaries located far from the wellbore. Case histories are presented for 2 installations of the wireless technology in the Brazilian deepwater pre-salt environment. The first case history presents the installation of a wireless gauge system that successfully transmitted high quality pressure and temperature data to a subsea receiver for a period of 873 days until the receiver's recovery from the seabed. The results show clear evidence of inter-well interference resulting from production in both near and far located wells. With certain producing wells being located at least 12km away from the observation well, this demonstrates that there was excellent reservoir connectivity across the field. The second case history was targeted at monitoring for interference effects resulting from an extended well test being performed on a well located 15km away. At the time of authoring this paper the survey has been on-going for 341 days and whilst there is no evidence of connectivity, the long term pressure build-up monitoring beyond the end of the DST has provided useful data. For both case histories the data collected has proved very useful in reducing uncertainty during the early stages of field development. © Copyright 2015, Society of Petroleum Engineers.

Gell C.,Expro | Dawson M.,Expro | Emslie M.,Premier Oil | Cruickshank B.,Premier Oil | Fairnie N.,Premier Oil
Proceedings of the Annual Offshore Technology Conference | Year: 2015

Like most companies today, Premier Oil (Premier) have been developing a Well Integrity Management System (WIMS) in order to provide a broader insight into both surface and subsurface well integrity issues. In addition to evolving their WIMS policies and procedures, Premier also chose to implement an effective and integrated well integrity data management software system to improve safety and operational efficiencies in the field, to increase production through reduction of well shut-in times, and to create a positive and proactive culture of managing well integrity which would allow Premier to proactively monitor and manage well integrity issues. This paper focuses on the reasons for implementing a well integrity management software system, the benefits to Premier by implementing the system, and how the system is used across all of Premier's assets. Premier started by collecting and collating data to understand whether or not a well was operating within its safe operating limits, this included information from other applications to fully understand the well integrity picture. From that, a database of the wells was set up, wellhead templates created, test types and data input forms generated, and incorporation of Premier's WIMS policies and procedures into the application. During the first year of implementation, the goal was to create a baseline of well integrity statuses for the current well stock and to establish workflows to manage the well integrity issues more effectively. The overall number of wells Premier operates is growing significantly with new and future developments, and hence this baseline establishment of good well integrity practices is preparing the company for future challenges and potential production concerns if well integrity issues arise. Additionally, there were qualitative objectives: Improvement in the monitoring and managing integrity issues proactively; Increased visibility of well integrity management within and outside the company; Ease of accessing all of the well integrity information and analyzing that data to find and fix problems; Improvement to data accuracy and availability to increase productivity by having up-to-date knowledge of well integrity issues. To-date, Premier has already seen an improvement in understanding well integrity issues across all their assets. Prior to implementation of the new software, data was stored on spreadsheets with only key personnel involved and understanding integrity issues. Now a more informed group recieve quick notification when wells are operating outside their agreed parameters, which has led to an overall improvement in proactively managing well integrity issues. Additionally, Premier also expects a more stringent regulatory environment in the future, at which time the existing spreadsheet-based system would no longer be workable or acceptable to external authorities. Copyright © (2015) by the Offshore Technology Conference All rights reserved.

Champion B.P.,Expro | Elliott D.,Expro | Van Kranenburg A.,Royal Dutch Shell | Hals K.,Royal Dutch Shell | Combe C.,Royal Dutch Shell
Society of Petroleum Engineers - Offshore Europe Oil and Gas Conference and Exhibition 2011, OE 2011 | Year: 2011

The big-bore, high flowrate completion design used on Ormen Lange features a high-set production packer and large bore 9 5/8'' production liner. This completion design makes it impractical to install a traditional cabled Permanent Downhole Gauge (PDG) system close to the producing sandface. With separation distances of greater than 1,000 meters between the producing sandface and the PDG, and frictional pressure drops and gravity head differences to contend with, there is significant uncertainty in how the pressure measurements recorded by the cabled PDG relate to the true flowing sandface pressures. For wells operating on drawdown constraint, reducing these uncertainties allows the drawdown to be optimised, which is critical to maximising production and exploiting the field reserves effectively. This paper presents a case history of the development, qualification and first time installation in the deepwater subsea environment, of a new cableless communication system. The system provides two-way communications between a battery powered pressure / temperature monitoring system located remotely at the producing sandface, and the onshore control room located at Nyhamna in Norway. The cableless communications technology functions by transmitting low frequency electromagnetic (EM) signals using the steel casing or tubing of the completion, or the rock formation, as a signal path. For Ormen Lange, high accuracy and high resolution pressure and temperature data is measured at the sandface using a precision quartz crystal sensor. This data is then transmitted in real-time through the cemented large bore production liner to a signal pick-up located above the production packer. Data is then transferred from the pick-up to a seabed transceiver via a cabled link and then onwards to the onshore control room. The communication channel is two-way, thus enabling the downhole system to be reconfigured on command from the onshore control room. Cableless gauge systems installed in several Ormen Lange wells have successfully transmitted high quality, high resolution pressure and temperature data recorded at the producing sandface, to the onshore control room and then onwards to the A/S Norske Shell internal data network. The data is being used for multiple purposes, including pressure build-up (PBU) analysis at the sandface, to determine permeability thickness and skin damage, to monitor the sandface completion efficiency and integrity, to maximise the production rate and as a diagnostic tool to determine gradient and confirm the density of the wellbore fluids during early stage well production clean-up. This first time application of a new cableless reservoir monitoring technology is enabling wellbore uncertainties to be reduced in the Ormen Lange big-bore high-rate gas wells. This has lead to production optimisation and an improved reservoir understanding, the learnings of which have been applied across the wider Ormen Lange field development, even for those wells having no cableless monitoring system installed. Copyright 2011, Society of Petroleum Engineers.

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.

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