Subsurface generation of hydrogen sulphide (H2S), commonly known as reservoir souring, is a clearly identified but, still not fully understood phenomenon associated with water injection for secondary oil recovery. A large number of North Sea fields have been under seawater injection for many years, yet the majority are relatively poorly documented in terms of how and when souring developed and the amount of H2S being generated between injector and producer well pairs. As part of ongoing work to verify the results of reservoir souring simulations, using empirical data, an exercise was undertaken to collate souring information from a number of older fields, with the objective of attempting to identify trends in, or factors impacting, souring development. A review of available historic data from the Gullfaks field was made; linking measured H2S values, well test data, water analyses and tracer data to identify long term souring patterns, the amount of H2S produced relative to injected water and to determine the effectiveness of the different mitigation strategies used in the field. The Gullfaks field in the Norwegian sector of the North Sea began production in 1985 and has been widely cited in connection with the introduction of nitrate treatment as a mitigation method for reservoir souring. A number of key observations were made for Gullfaks. Souring development appears to follow a dual pattern of initial production of H2S, coincident with or shortly after breakthrough of injection water, followed by a subsequent decline; thereafter, sometimes several years later, a gradual increase to much higher levels is recorded. This implies that different types of souring patterns are being observed. On the basis of improved understanding of souring development and data availability, a review of the effectiveness of mitigation techniques used in the field was undertaken. The interpretation indicates that the previously reported effect attributed to use of nitrate could also be explained by the natural progress of souring development in the field. The work flow and methods of data interpretation opens the way to further full field evaluations as a means of improving the precision of souring simulation and assessment of mitigation methods

An increasing incidence of amorphous deposits in both production and water injection systems is causing considerable problems for offshore fields. The amorphous deposits are typically comprised of both organic (biological or hydrocarbon) and inorganic material and can differ considerably in composition. System deposits of this nature have been previously characterised as ‘Schmoo’ and within our company the descriptive, but non-specific term ‘Black Sticky Stuff’ has been coined. The challenge with use of this terminology is that it makes accurate description of deposits from different systems difficult and does not allow similar materials to be easily categorised. This paper describes the work undertaken to better understand the composition of samples taken from different systems, both production and injection. Systematic analysis has led to the development of a classification matrix for deposits related to their major components. From the classification, improved knowledge has been gained to enable increased consistency of removal or preventive methods. Some initial observations are made on an unusual form of deposit - being either a product of, or promoting corrosion - being encountered in water injection systems. The material is causing concern with regard to system integrity and intervention in injection wells. Work to define the root cause, and develop removal methods of this type of deposit is presented.

The Snorre licence operating in blocks 34/4 and 34/7 of the Norwegian North Sea was the first to install surface operated zonal control to allow selective production from different sections of the reservoir. The concept of Downhole Instrumentation and Control Systems (DIACS) has, subsequently, been further developed and refined and is used today, by many operators. The Snorre field remains at the forefront of this development and the technology has been employed in a further 17 wells (both injectors and producers) across the field. The Snorre reservoir is highly heterogeneous and faulted and consists of layers with differential pressures of up to 150 bar. This has lead to many instances of rapid water and gas breakthrough in individual zones, whilst other layers have remained largely un-drained. The use of DIACS has lead to improved reservoir exploitation and has formed the basis for implementation of the concept as the preferred completion solution for the northern area of the field, via the Snorre B platform. This paper will focus on the use and advantages of advanced completions from both a reservoir and production engineering viewpoint; it will summarise experience gained with regard to mechanical aspects of the completion hardware; data collection and management and will discuss future plans and expected benefits of this type of completion system. Introduction The Snorre Field, operated by Statoil ASA, is located in Blocks 34/4 and 34/7 of the Norwegian sector of the North Sea, approximately 150 kilometers North-West of Bergen (Figure 1). Snorre A, which started production in 1992, consists of a tension leg platform (TLP) and a sub-sea production system (SPS), in a water depth of about 350 meters. Produced oil is exported to Statfjord A, whilst gas is partly re-injected and partly exported to Statfjord A. As of November 2004 Snorre A consisted of 30 oil producers and 23 injectors, including subsea wells. Snorre B, which came on-stream in June 2001, is a semi-submersible drilling, process and accommodation platform. Oil is exported to Statfjord B and the produced water and gas are reinjected. Presently, six production wells and three injectors are connected to Snorre B. The Snorre reservoir rock is Late Triassic / Early Jurassic age with the Statfjord Formation overlaying the Lunde Formation. Middle to Late Jurassic crustal extension generated the present setting in rotated fault blocks, capped by Early Cretaceous and younger sediments (Figure 2). The Snorre field is a complex reservoir consisting of fluvial sandstones representing various fluvial styles and subfacies. The lateral extent of the channel belts varies from 300m to several kilometres and the permeability from a few hundred milli-Darcies to several Darcies. The channel belts are stacked and interbedded with mudstone and under dynamic flowing conditions several pressure regimes have been developed due to the limited vertical and lateral communication. It was originally planned that the under-saturated oil would be recovered with down-dip water injection as the drive mechanism, but this was changed at an early stage to Water Alternating Gas (WAG) injection, in order to improve oil recovery as well as providing a method to independently utilise excess gas. As of November 2004 the Snorre Field had an expected Stock Tank Oil Originally In Place (STOOIP) of 532 Million Sm3 with expected oil reserves of 242 Million Sm3. Overview of Applications To date, 55 remotely operated sliding sleeves have been installed in wells in the Snorre field. The sleeves are both hydraulic and electro-hydraulic in operation. Installation has been in production, WAG injection and multifunctional wells. Hardware from four different suppliers has been utilised. Of the 55 installations, 41 are still operational (Figure 3) - in some cases, however, loss of zonal control in the well can be attributed to failure of an isolation packer or poor cement quality behind the liner, rather than to failure of the sleeve itself.

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Calcium carbonate (CaCO3) scale formation in production wells and process systems is a well-known challenge in the oil and gas industry. Various strategies are selected to prevent scale formation (proactive, e.g. by scale inhibitors) or to remove scale when it has formed (reactive, e.g. by acid treatment), depending on the severity of the problem and the complexity of the production system. Lack of access for remedial actions may be a limiting factor in subsea and unmanned installations and scaling may represent a larger risk of production losses or system failures. The scale management strategy and design of new wells during field development are based on thermodynamic calculations, kinetic studies and field observations. Experience has shown that wells with high temperature and high pressure drops are more prone to downhole calcium carbonate scaling. Field experience has been collected and systemized based on operations of oil and gas-condensate fields in the North Sea and Norwegian Sea. The observations have been compared to thermodynamic calculations and aligned to kinetic modelling, defining the critical saturation ratio (SRCaCO3) for scaling. The result is a graphic which has proved to be a powerful tool in planning of new wells and is described in this paper. The Oseberg field in the North Sea is producing from oil and gas-condensate wells at various reservoir temperatures (98-128°C). The field comprises platform and subsea production systems and one unmanned wellhead platform. Seawater has been injected for pressure support in some areas, while gas injection or depletion are the driving forces in other segments. The CaCO3 scale potential and management strategy have been evaluated for new wells in a field life perspective. Risk of production losses and maximizing cost benefit are key selection criteria, and the variety of wells requires individual solutions. The paper discusses the need for downhole continuous injection of scale inhibitor, compared to batch scale inhibitor squeeze treatments and/or acid treatments. Guidelines for optimum operation of these wells to avoid scaling are presented.