The setting and possible future of the petroleum industry in the Netherlands is briefly discussed. The result of a risk assessment shows, that the Dutch hydrocarbon province can be divided in low, medium, high and very high-risk areas for new capital investments. The assets of operators in the Netherlands have been evaluated on exploration, production, storage and pipeline potential, now and in the future. Despite the presence of potential new plays, exploration activities are expected to decrease in the near future. Despite the possible development of marginal fields, which will be not adding major reserves, the production reserves will decrease in the next 10–15 years and many fields will be abandoned. However storage, pipeline infrastructure and gas marketing are expected to increase in the future, mainly because of the liberalisation of the Dutch gas market.

Once the great size of the Groningen Field was fully realized late in 1963, exploration in the southern North Sea was a natural development as the reservoir bedding dipped westward. The origin of that bedding was not certain, one possibility, dune sands, led immediately to a program of desert studies.

Licensing regulations for Netherlands waters were not finalized until 1967, offshore exploration beginning with the award of First Round licenses in March 1968. In the UK area, the Continental Shelf Act came into force in May 1964, paving the way for offshore seismic, the first well being spudded late in that year. The first two wells were drilled on the large Mid North Sea High; both were dry, the targeted Rotliegend sandstones being absent. Then followed a series of Rotliegend gas discoveries, large and small, west of Groningen, so that by the time exploration began in Netherlands waters the UK monopoly market was saturated and exploration companies were already looking north for other targets including possible oil.

The Rotliegend was targeted in the earliest wells of the UK central North Sea even though there had already been a series of intriguing oil shows in Chalk and Paleocene reservoirs in Danish and Norwegian waters. These were followed early in 1968 by the discovery of gas in Paleocene turbidites at Cod, near the UK-Norway median line. The first major discovery was Ekofisk in 1969, a billion-barrel Maastrichtian to Danian Chalk field. Forties (1970) confirmed the potential of the Paleocene sands as another billion barrel find, while the small Auk Field extended the oil-bearing stratigraphy down to the Permian. In 1971, discovery of the billion-barrel Brent field in a rotated fault block started a virtual ‘stampede’ to prove-up acreage awarded in the UK Fourth Round (1972) before the 50% statutory relinquishment became effective in 1978.

Although the geology of much of the North Sea was reasonably well known by the end of the 1970s, new oil and gas reservoirs continued to be discovered during the next two decades. Exploration proved the Atlantic coast of Norway to be a gas and gas-condensate area. The stratigraphiC range of reservoirs extended down to the Carboniferous (gas) and Devonian (oil), while in the past decade, forays into the UK Atlantic Margin and offshore Ireland met with mixed success. During this hectic activity, Netherlands exploration confirmed a range of hydrocarbon-bearing reservoirs; Jurassic oil in the southern Central Graben, Jurassic-Cretaceous oil derived from a Liassic source mainly onshore and, of course, more gas from the Rotliegend. German exploration had mixed fortunes, with no commercial gas in the North Sea and high nitrogen content in Rotliegend gas in the east. Similarly in Poland, where several small Zechstein oil fields were discovered, the Rotliegend gas was nitrogen rich. The discovery of some 100 billion barrels of oil and oil equivalent beneath the waters of the North Sea since 1964 led to an enormous increase in geological knowledge, making it probably the best known area of comparable size in the World. The area had a varied history over the past 500 million years: platete-tonic movement, faulting, igneous activity, climatic change, and deposition in a variety of continental and marine environments, leading to complex geometrical relationships between source rock, reservoir and seal, and to the reasons for diagenetic changes in the quality of the reservoir sequences. Led by increasingly sophisticated seismic, drilling and wireline logging, and coupled with academic research, the North Sea developed into a giant geological laboratory where ideas were tested and extended industry-wide.

Aeolian sands are the main reservoir rock in some of the largest gas fields, such as the Shell-Exxon Groningen Field, operated by NAM. Although aeolian reservoirs have been studied for many years, there is still room for improvement in the predictive modeling of such reservoirs. A pilot project with this objective was initiated by SIEP B.V. in 1997, together with Heriot-Watt University in Edinburgh, UK and with Uppsala University, Sweden, to evaluate the factors influencing aeolian systems, and to formulate a forward model using ‘fuzzy logic’.

The project was initiated to develop a fuzzy system for generic modeling of aeolian architectures. The key aims were to be able to predict the type, amount and distribution of major facies in generic aeolian systems and specifically to model regional-scale architecture in the sub-surface. Fuzzy rules and sets, which defined the behaviour of aeolian systems, were constructed and used to modify the pre-existing fuzzy modeling software which had been designed for shallow and deep marine systems. The modeling procedure used input data appropriate to the Rotliegend climate, and was validated by comparing the resulting models, in terms of thickness and spatial distribution of facies types, to well data from the Upper Rotliegend interval of the Lauwerszee Trough area, NE Netherlands (Figures 1 & 2).

For the first time this project attempts to directly correlate magnetotelluric and geochemical data with the aim of creating a model on the regional distribution of potential pre-Westphalian source rocks deposited in marine environments in the North German basin.

Analysis of the magnetotelluric data shows, that there is a deep good conductor at the north-eastern fringe of the North German basin around the islands of Rügen and Usedom and on the mainland north east of the Anklam Fault. Through integration with seismic data and the offshore well G14 the conductor can be correlated with the Cambro-Ordovician Scandinavian Alum shales. To the south an adjoining area approximately corresponding to the depo-centre of the Rotliegend basin lacks a deep good conductor. Therefore it can be assumed that a regional distribution of comparable source rocks is unlikely. Another excellent and important conductor starts to the south west of the Lower Elbe Line extending along the Dutch-German border into the North Sea, and into the Münsterland. Its place in the local stratigraphy has not been adequately established. It is most likely that this good conductor corresponds to the black shales of the Early Namurian and the Dinantian, which is the case in the boreholes Münsterland 1 and Pröttlin 1 for example. In this paper they are collectively called Rhenohercynian Alum shales. On the Dutch-German border a transition into the “Bowland Shale” facies or equivalents is to be expected. It cannot be ruled out that even stratigraphically older black shales, possibly from the Cambro-Ordovician could contribute to the high integrated conductivity of the deep good conductor.

The evidence of highly conductive layers in the deep subsurface poses the question whether these layers could be potential source rocks for the gases in the north German gas fields. This question can be answered with a clear yes. Gas and isotope geochemical studies on gases from producing Rotliegend deposits have shown that Rhenohercynian Alum shales have been a significant source for these fields. This will be illustrated in detail using the gas fields from the production province “Ems Estuary” as an example.

The Broad Fourteens Basin is a NW-SE trending Mesozoic structural element that was affected by inversion movements during the Late Cretaceous (Subhercynian Phase) and Early Tertiary (Laramide Phase). Since the overlying Tertiary section of this area is relatively little studied, a multi-disciplinary investigation was initiated using both seismic and well data. The present study is the first phase of that project and deals exclusively with the stratigraphical framework and sedimentary development based on well logs from approximately forty wells.

The Tertiary sedimentary section in this area (maximum thickness up to approximately 800 m) consists of siliciclastic rocks that generally correlate well with the established lithostratigraphical framework of the Netherlands. However, the highly variable thickness of these lithological units, illustrated by isopach maps for all units, reflect the intricate pattern of sea level movements, differential vertical movements and the ensuing erosion, that took place in this tectonically active area.

Well P06-02, one of the most complete sections in the center of the area, was selected for detailed biostratigraphical analysis to support further stratigraphical subdivision and correlation. This yielded information on both the distribution pattern of various lithological units and the influence of large, partly global, events during basin development. It is concluded that application of detailed sequence stratigraphy in the study area is very problematic and only 2nd and some 3rd order cycles could be recognized.

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.

Gas Field Planning Tool (GFPT) was developed in 1990 by the Shell Group of Companies to fill the need for a tool for gas field planning and development using deterministic subsurface and surface models. Main initiators were Shell Canada, NAM (the Netherlands), Shell Expro (UK) and BSP (Shell Brunei), as these companies are major gas producers.

Shell Companies now have several years experience with using the GFPT. Application ranges from simple single field models to corporate-level models with a large number of gas reservoirs and wells. Shell companies now using GFPT models are Shell Expro (UK), BSP (Brunei), SSB (Malaysia), Shell Canada, SPDC (Nigeria), SDA (Australia), Woodside (Australia), PDO (Oman), NAM (the Netherlands), New Business Development (e.g. Lunar Project) and in future also Shell Egypt.

NAM currently has a GFPT model for the Anjum field in Friesland and for the Ten Arlo field in the north of Holland.

GFPT is currently being migrated to an HFPT (Hydrocarbon Field Planning Tool), which can also be used for planning of condensate, oil and water developments and for control of hydrocarbon compositions in the network using PVT de-lumping at the well head (e.g. for LNG plants) and optimisation techniques (linear, non-linear or based on bean-back lists).

Value Analysis is a powerful tool to increase the value of a capital investment project and to capture cost saving opportunities. It is a method conceived during WorldWar II and frequently used on infrastructure projects, especially in the USA.

The Value Analysis process typically consists of a well prepared 3 to 5 day workshop with focus on generating ideas to improve the current engineering concept. Emphasis is on screening all proposals in order to identify the most promising ideas. The workshop results in a number of proposals to modify the existing engineering concept.

Stork Engineers & Contractors have used the Value Analysis method on several projects as well as in proposals for Engineering, Procurement and Construction (EPC) projects in the Exploration and Production (EP) industry.

Typical results of Value Analysis led to a decrease of Total Cost of Ownership by some 10 to 30%. A well facilitated Value Analysis workshop also leads to mutual trust and understanding between the parties involved.

A key element in a Value Analysis is (re)definition of the proposed functionality of a project. This is done through challenging the existing technical concept by increasing this functionality or by meeting this functionality at a lower cost.