Approximately 50% of all installations in the UK offshore sector are small steel jacket structures that are normally unmanned. These platforms often have severe limitations on the permissible lift weight of temporary well servicing equipment. During a study into the extent of this problem, it was observed that a significant proportion of gas production is reliant on wells producing via these normally unmanned installations, and that production from this source has declined dramatically in recent years. When compared to manned installations where (intervention is easier and therefore assumed more frequent), production decline is less severe. An operator identified a production enhancement opportunity on an unmanned installation in the North Sea UK Sector. The well needed extensive intervention in order to be brought back to production using coiled tubing (CT). Due to the restricted crane capacity (less than 7.5 ton) on the platform, a conventional CT package could not be lifted on board. Through a collaborative project, an existing CT equipment package was modified to be lifted within this weight limit. A boat spooling technique was used to install the CT string onboard the platform without using a crane as it was much heavier than the crane limit. Throughout the equipment modification project, the principles of efficient rig up and optimized fast, safe working where applied. The installation of this equipment on the platform was conducted quickly and easily, validating this approach and improving on previous experiences significantly. This paper demonstrates how conventional equipment can be adapted to meet the challenges faced with platforms considered inaccessible to perform CT interventions. Introduction The application of Coiled Tubing (CT) interventions within the offshore environment has matured significantly over several decades. However, the use of CT to perform intervention services on small steel offshore platforms is a relatively uncommon practice. These installations create a nique challenge for access to perform intervention operations as many are classified as Normally Unmanned Installations (NUI). Despite wells being constructed with a standalone completion design philosophy (similar to subsea wells), often intervention is required in many wells, particularly as North Sea infrastructure ages and matures. The need for CT operations is being realised more frequently by operators of wells on these types of installation in the North Sea. These NUIs usually have severe limitations on size of deck area to work with, limited provision for personnel accommodation, and low crane lift capacity. To compound the problem, many of these platforms are getting older, and their cranes are being de-rated. Crane capacity is a function of boom angle. In bad weather conditions it is often necessary to extend the boom to avoid the risk of the supply vessel hitting the platform. Bad weather also affects the maximum safe lift possible from an offshore platform. Crane replacement, however, is difficult and very expensive. As a consequence of these access restrictions, cost effective CT intervention is rarely performed on United Kingdom Continental Shelf NUIs. In the past, the only effective method of accessing wells on NUIs has been to use a drilling jack up rig or workover jack up rig. The availability of workover rigs suitable for this work has been extremely limited and the cost of using a drilling jack-up has become prohibitively expensive in the past five years.
Internal corrosion is prevalent in offshore wellheads in the Siri field in the Danish North Sea. Certain wellhead components must be replaced with corrosion-resistant parts. During the wellhead maintenance work, local regulations require a dual barrier and each of these barriers must be tested independently. The casing below the wellhead is completed with fiberglass lining. Standard bridge plugs and standard cleaning methods of tubing are incompatible with the lining and are not considered feasible.This paper presents an alternative solution that uses two inflatable bridge plugs as an isolation method and provides the ability to remove the scale present in the well in the setting area. It details yard tests performed to ensure the chosen technique does not damage the lining of the tubing and can efficiently isolate the wellhead. It also reviews results of several operations performed between 2006 and 2007, in which inflatable bridge plugs were successfully set and retrieved in the fiberglass-lined tubing. Review of the problemThe original recovery / gas disposal design for Siri field was SWAG (simultaneous water and gas injection). 1 This design was derived from the lack of gas export and the ability to lower the gas compression pressure requirements by mixing it with water; however due to the mixture in the injected fluid (ca. 0.5% CO 2 in the water, high pressure and therefore high partial pressure of CO 2 ) together with oxygen content created several corrosion issues. The corrosion can severely affect both the tubulars and the wellhead components. The wells require some sort of corrosion protection in order to avoid having to change completion often; however the corrosion protection systems have not always been successful. On some wells of the Siri field parts of the wellhead needed to be changed with inconel inserts due to corrosion while the tubulars are GRE lined. It is required to pressure test the wellheads while having a double barrier in place. To protect the tubulars from corrosion the following options are available:• Install alloy completion • Perform corrosion protection treatments • Install lined tubulars Each one of these options has advantages as well as disadvantages.Chrome or alloy completion. Chrome or alloy completions are the best possible solution as these are resistant to most of the wellbore fluids and have good mechanical properties as well. The main disadvantage is high product cost and ordering lead time, which is much longer than traditional steel. The use of this technique is increasing all over the world particularly in the North Sea as it guarantees long term performance. Corrosion protection treatmentsCorrosion protection systems like cathodic protection are available and less expensive than chrome or alloy tubulars. However, the main disadvantage is the limited effect on particular types of corrosion where the electrochemical mechanism is clearly understood and in less severe environments. 2, 3
Subsea Well Interventions offer many challenges. The population of subsea wells is now in the region of 4000 and is anticipated to continue to grow, with expansion into deeper waters and more hostile environments. Historically, the cost of intervention on subsea wells has negatively influenced its uptake; however, this is changing with advancing technologies, as operators seek to improve recovery from their subsea assets. Fluid intervention does not require vertical well access for wireline or coiled tubing services: it involves pumping chemicals into the well in a controlled, safe manner. There are a number of fluid intervention applications, examples of which are: to protect the well against scale and hydrates; pumping of kill weight brine for the purposes of well control; cleaning the lower completion or stimulating the reservoir to tackle formation / production issues that can evolve throughout the life of the well. In 2008, an operator in the North Sea utilised the first MARS based subsea well intervention system, to carry out scale squeeze operations in the on a North Sea field from a DSV. Further successful campaigns have been completed in 2009 and 2010 in addition to a 10,000 psi system being ordered for other fields. By adopting a standardised method for scale squeeze operations, Shell has been able to reduce the cost and maximise the efficiency of their operations. Subsequently an operator in Angola has adopted the same philosophy for their subsea field while considering additional MARS options for well sampling and metering; successful operations where performed in 2009 and 2010 and 2011, allowing continuous production while reducing the cost of intervention. A major project in the Gulf of Mexico has been sanctioned where the technology will be used also. This paper will describe the operational and cost benefits of utilising MARS for subsea well intervention and update on the operational performance of this methodology as it matures. . Multiple ApplicationsMARS is a production optimization technology that establishes the wellhead as the unit of production, enabling processing equipment to be mounted directly onto production trees. The principle is simple: by introducing a coaxial flow path insert into the tree, well fluids are directed externally to a flow loop that houses a processing technology. The flow is returned to the wellhead and back into the existing flowline infrastructure. Processing hardware is installed between the existing isolation barriers and eliminates the need for expensive, high risk well intervention, field shut down, or flowline decommissioning, while minimizing production losses. The technologies and the range of possible solutions enabled by MARS are evolving. The existing or emerging processing technologies that can be fitted on to any wellhead with minimal risk include:• multiphase pumping • multiphase metering • fluid sampling • chemical injection and well stimulation • sand management • separation • bulk water management and re-injection • raw seawater injection • pressure...
Critical coiled tubing treatments, such as fill cleanouts of sub-hydrostatic wells and perforations of small reservoir intervals have historically posed a high uncertainty for Norwegian operators due to nature of the complex completions i.e. long and large monobore completions. The complexity is exacerbated with the strict offshore environmental regulations that limit the fluids that can be used for intervention operations. Fill cleanouts on these wells with CT face the difficult challenge of achieving the desired rate for pumping seawater which leads to the need for better understanding the downhole conditions while performing the operation. Without understanding these conditions it can be costly and create operational complications. A way to provide insight to the changing conditions during the cleanout operation is to use CT enabled with real time downhole measurements. The use of real time downhole measurement allows recognition of the wellbore response due to changes in hydrostatic pressure as the fill/debris are removed from the wellbore and adjustment of the operational parameters needed for effective treatment. Following the cleanout, this ability to adjust the parameters allows efficient well kick off by optimizing the use of nitrogen. This paper will present several case histories incorporating real time downhole measurements for effective and efficient clean outs as well as optimized well kick offs in the Norwegian sector of the North Sea. Introduction The Valhall field is an Upper Cretaceous, asymmetric, chalk anticline that forms an overpressured, undersaturated, oil reservoir located in the Norwegian sector of the North Sea. It is characterized by high porosity (25 to 48%) and high oil saturation (92 to 97%).1,2 Fill cleanouts are often necessary during the life of these wells as the unconsolidated nature of the reservoir and the compaction mechanism contribute to production of particles and fines which plug reservoir perforations and obstruct wellbore access. Cleanouts are also challenging in these wells due to the unpredictable nature of the fill to be found and the possible wellbore damage that can exist especially in old wells.2 Improved method for cleanouts It is generally accepted that many, if not all, coiled tubing downhole applications can be optimized with the availability of real-time downhole information. Many of the existing treatment simulators/monitors for these operations use calculated values for downhole parameters based on extrapolation from surface measurements - giving at best an approximate result. Realtime downhole measurements allow interpretation and job optimization with services delivered through coiled tubing. It provides the information needed to adjust job parameters immediately, to improve effectiveness, reduce risks, and optimize performance with the operation still in progress.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis work will describe the management of scale in a United Arab Emirates offshore carbonate reservoir. Field pressure is sustained by water injection, which contributes to the formation of scale in downhole tubulars. This scaling can cause both safety and production problems, for example, by blocking a subsurface safety valve or chocking flow at downhole nipples.ZADCO has initiated a successful strategy to manage the sulfate-scaling tendency in the completion tubing. Software is used to identify wells early on as potential scale candidates. This software uses real field measurements and analysis of injected and produced water information. The results are used to plan well monitoring and/or treatment. The identified wells are monitored using both slickline gauge measurements to measure actual scale growth and produced water surface analysis to update the software model.Early corrective action is performed using a specialized sulfate scale-dissolving fluid pumped from the surface. More aggressive treatment for larger scale accumulations is performed using a barge, coiled tubing unit, and specialized downhole jetting system.Results have shown that early diagnosis of the scale allows earlier, easier, and far less expensive scale removal treatment. The effect of scale on production decline is also reduced.
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