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This paper describes the application of underbalanced horizontal wells to develop some different tight gas reservoirs in the Netherlands section of the Southern North Sea. Underbalanced well design presented specific issues related to the nature of these reservoirs. The construction and production experience to date is evaluated and compared against similar wells drilled offshore UK. Also the benefits of the underbalanced horizontal well concept are reviewed. Introduction Most gas fields in the Southern North Sea produce from the Rotliegend sandstone formation that is of Permian age and deposited in both aeolian and fluvial setting. The Rotliegend reservoirs are characterized by a large variability. The average porosity varies between 8% and 18% with peak porosities ranging from 22–26%, while the average permeability varies between 0.01 mD and 100 mD. In parallel the compressive strength of the formation material shows drastic variations as well i.e. between 10 bar and 1000 bar. A significant portion of the Rotliegend reservoirs are characterised as tight gas, defined in this paper as having an average in-situ air permeability of less than 1 mD. Up to the 90's the preferred method of developing these types of tight gas reservoirs was through massive hydraulic fraccing. During the 90's the emphasis shifted to horizontal drilling. This proved successful in tight gas fields in the UK sector of the Southern North Sea where the (sub)horizontal drainholes connected productive natural fracture networks. In the late 90's underbalanced drilling (UBD) was introduced, in first instance to avoid the frequent drilling problems associated with total losses into these natural fractures. However, significant productivity gains were also observed and this became a key driver to apply the same UBD technology in tight gas fields in the Dutch sector of the Southern North Sea. This paper describes the experience to date offshore The Netherlands. Setting the Scene The average permeability cutoff used to define tight gas in the Southern North Sea is 1 mD or 10 times higher than the tight gas cutoff of 0.1 mD used onshore USA. The difference is due to the much higher offshore Europe well cost, which forces field developments to aim for a one order of magnitude or more higher well capacity and raised ultimate recovery to generate economic returns. Typically the initial well capacity offshore Europe should be of the order of 1*106 m3/d (compared to 0.1*106 m3/d onshore USA) while the ultimate recovery offshore Europe should be of the order of 1*109 m3 (compared to 0.1*109 m3 onshore USA). Hence the challenge has been to boost the well capacity and increase ultimate recovery of these tight gas wells to increase their economic attractiveness for development in the Southern North Sea setting. UK Tight Gas Experience In the 80's hydraulic fracturing of deviated wells was the method of choice for developing tight gas reservoirs in the Southern North Sea (Ref. 1). Although sound in principle, in practice problems were experienced caused either by poor cleanup due to fluid incompatibility, proppant back production causing fill and erosion of surface facilities or early water breakthrough due to fracturing into the water leg. In the 90's horizontal drilling became common practice as new drilling technologies developed and proved to be very successful in several UK Southern North Sea tight gas fields. Table 1 compares the productivity index (PI) achieved by hydraulic fracturing and horizontal drilling in 3 UK fields and shows 2–8 times higher productivity from horizontal wells. The success of the horizontal wells largely originates from intersecting productive natural fracture systems.

The economics of small gas field developments in the Southern North Sea away from any existing infrastructure is particularly sensitive to subsurface uncertainties. Applying latest geophysical approaches is a key aspect of obtaining sufficient grip on these parameters and ensuring robust project economics. For the Alpha field, the structural uncertainty due to poor seismic imaging was identified as critical and therefore a dedicated seismic imaging project was undertaken. It involved re-processing the existing seismic data with the latest velocity modeling and imaging technologies, such as Reverse Time Migration. It led to a clear improvement of the seismic character at objective level as well as a more consistent depth image. As a consequence, the expected volume of gas in place increased by 50% and additional reservoir targets were identified, considerably improving the project economics. In addition, a High Definition 3D seismic image of the shallow subsurface was for the first time successfully created over the area to assess any potential geohazards and ensured that the proposed and selected development concept had mitigations against these hazards and their consequences.

In contrast to oil field development, gas field development requires tight integration of subsurface, surface and economic issues due to the difficulty of storing surplus produced gas and the large effect of the back-pressures in a surface network on the individual well performance. As a major gas supplier the Shell Group, and in particular NAM, has extensive experience in this field.The gas production from onshore fields in the North Friesland area is a recent NAM development. A 10 million cubic meter per day LTS gas treatment installation located near the village of Anjum came on stream in 1997. Production initially started from 3 wells in 2 fields to deliver gas to the Gasunie grid at Grijpskerk. The total area comprises 10 fields and 4 remaining prospects and is planned to be fully developed by the year 2001, using wet gas pipelines to route the production to either the Anjum LTS installation or the Grijpskerk SilicaGel installation.The Rotliegend reservoirs in this part of the Netherlands are very heterogeneous and require a more detailed subsurface simulation than feasible with the standard NAM tool for gas field development (GENREM). In addition, the area is close to the Waddenzee and based on extensive ecological research, NAM uses a stringent, self-imposed ecological constraint, whilst evaluating the development plans for this area. Detailed subsidence studies have been run using subsidence-modeling tools, which run under a software user-interface called FrontEnd, an in-house development by the Shell Group. Also running under this interface is an application for gas field development called Gas Field Planning Tool (GFPT). GFPT combines a detailed subsurface simulator with a surface simulator using a development planning module, which handles economic and operational aspects of the integrated model. Lastly, the interface gives access to a powerful command language and a mathematical toolbox, which can be used to define almost any missing functionality.Making use of the flexibility offered by the FrontEnd interface and with help from available expertise in RTS (Shell Rijswijk), an integrated GFPT model was built, which not only incorporates operational and economic constraints, but also does optimization and subsidence analysis. The model is used to evaluate all development options and scenarios for this area in a consistent manner. Therefore, all proposed development plans are optimized within all applied constraints whether they are related to surface, subsurface, economic, or environmental aspects.Production history and well performance are very close to those predicted by these detailed models, which will allow accurate prediction of future field performance and subsidence.