When, in 1952, one of the first wells drilled in the northern part of the Netherlands, Harkstede, found traces of gas in Lower Permian sands, there was little rejoicing. The target had been the Upper Permian Zechstein formation and the drillers were looking for oil. The next well, TBR-1, drilled in 1955, also failed to find oil in the Zechstein, and bottomed out before reaching the Lower Permian.
So when on July 22nd, 1959, Slochteren 1 discovered large quantities of gas in the Lower Permian Rotliegend formation, there was simply satisfaction that there appeared to be enough gas to be commercial. Similar emotions were felt when Slochteren 2, 30km to the SE, also found gas in the Rotliegend.
Only when a further well, drilled 20 km north-east of Slochteren near Delfzijl, also found large quantities of gas, was the significance of these discoveries realised. All the wells had a gas water contact at the same depth, indicating that they were not three separate discoveries but one super-giant: the Groningen Field. When TBR-1 was re-entered and deepened, it also found gas - a 180m column in the Lower Rotliegend. Eventually, the field would prove to cover an area of 900 km2 and hold a massive 99 Tcf (2,800 Bm3) of recoverable gas. Despite the many discoveries made since 1959, Groningen remains the biggest field in Europe and about the tenth largest in the world. In comparison Troll, the largest offshore gas field in the North Sea, discovered in 1979, had original reserves of 1,325 Bm3.
However, the size of Groningen is not its primary significance. More important is the significance of the discovery to the oil industry and to Europe at the time, and the lessons which have been learnt from it, both through efficiently extracting the gas and exploiting the resource over time.
Groningen discovery opens up North Sea play
Up until 1959, the North Sea had been written off as a possible site for major hydrocarbon discoveries. In fact, when the eminent geologist George Lees had presented a paper to the Geological Society of London in 1936, suggesting oil could be found in Britain, he was virtually laughed out of the room, and there had been relatively little interest in the idea since then. But Groningen changed all that, as the existence of such a vast resource on the edge of continental Europe obviously begged the question: could the play extend into the North Sea?
Ultimately, the discovery opened up the whole of the North-West Europe to the hydrocarbon industry, both on and offshore. Many countries were not prepared for this, and legislation had to be rushed in, including methods of demarcating the offshore boundaries between nations, while systems for leasing acreage for exploration had to be defined. Nevertheless, a mere ten years after the discovery of Groningen virtually the whole of the southern North Sea below 58°N had been opened for hydrocarbon exploration.
The discoverer and operator of the Groningen Field is NAM (Nederlandse Aardolie Maatschappij), a company formed in 1943 to explore for hydrocarbons in the Netherlands, in which Shell and ExxonMobil are both 50% stakeholders. Initially, NAM was reluctant to make known the suspected size of its discovery, fearful of a rush of competing companies to the area, so estimates were originally put at around 2 Tcfg (60 Bcmg).
The huge size of the discovery led the developers to concentrate production through collections, known as ‘clusters', of closely spaced wells, each one with a single treatment plant and control centre, which helps minimise costs. Production started in December 1963, with a few clusters of about six wells, but NAM very soon realised that more clusters would be required, with a concentration of large groups of wells in the north and central parts of the field to keep the reservoir pressures equalised. There are now about 300 wells, spread over 29 production clusters, producing approximately 1,200 Bcfg (35Bcmg ) a year, an average of 3.3 Bcfg/d.
Groningen gas spreads through Europe
The effect of Groningen gas on the economy of the Netherlands was rapid and immense. Within a few years, a network of pipes had spread across the country and the majority of houses had been converted to natural gas as their main energy source. Many businesses, including the huge number of glasshouses used in market gardening across the country, were also able to save costs by switching to natural gas from expensive ‘town gas' made from coal.
Gas from Groningen was also soon being exported across Europe and even to North Africa, and the money earned in tax revenues from gas sales enabled the Dutch government to improve the average standard of living, health and education of the whole population. Since natural gas is the cleanest fossil fuel with the lowest CO2 emissions, it had the added advantage, as we discovered later, of helping to clean up the air of Europe by removing the millions of coal-fired stoves and manufacturing units.
For the first decade of production the policy was to extract the gas from Groningen as fast as possible, so the Netherlands could reap the financial and practical benefits of this natural resource. The oil crisis of 1973, when the Arab members of OPEC proclaimed an oil embargo on all countries supporting Israel in the Yom Kippur war, brought about a new strategy. As the oil price rose and supplies dried up, governments, including the Dutch, started to think more seriously about ensuring continuity and supply of hydrocarbons for the future.
Preserve for future
Dutch legislation introduced in the 1970's encouraged oil companies to explore for and develop smaller accumulations, in order to extend the life of the Groningen field. The policy proved very successful, and many smaller fields have been discovered, with combined recoverable gas volumes of about 50 Tcf (1,400 Bcm) As a result, more that 50% of all natural gas reserves of the European Union is still produced from Dutch territory, with about two-thirds of this coming from the Groningen field. Groningen is used in a ‘swing' capacity, so that if demand, either locally and for export, exceeds the total supply from the smaller fields, the giant field can make up the difference.
Combined reserves of all other Dutch fields 50% of Groningen total
By the late 80's, approximately 50% of the resources of the Groningen field had been recovered, using the standard gas depletion drive mechanism. To ensure continued and efficient exploitation of the field, NAM decided to change to a gas compression drive system, using electrically driven compressors to help push the gas out of the reservoir. Looking to the future, further stages of extra compression may be needed in order to effectively deplete the field.
Underground Gas Storage
Demand for gas fluctuates both seasonally and from day to day, but optimum production from a field requires both steady and high pressure. Since the Groningen field is already more than 50% depleted, the natural pressure has dropped and is no longer sufficient to supply the required volumes at peak times.
To deal with this and ensure optimum depletion and longevity of the field, underground gas storage facilities have been developed, using two small, almost depleted gas fields to the west of Groningen, called Norg and Grijpskerk. During the summer, natural gas for which there is no demand is injected into the depleted reservoir rocks in these fields. This increases the reservoir pressure of the storage facilities so that they can quickly produce natural gas as required during the following winter. Norg, the largest of these facilities, can receive up to 848 MMcf (24 MMcm) of injected gas a day, and produces between 1.8 and 2.1 Bcfg/d (50 - 60 MMcmg/d) on demand, using a number of multipurpose wells.
Various other developments are underway to ensure optimum productivity and longevity for the Groningen Field. All 29 well clusters have been systematically renovated, installing new, more efficient and environmentally friendly compressors and cooling systems. They are unmanned and controlled from a remote central location, where there is real time monitoring of production, gas treatment, emissions, energy consumption and costs.
Groningen teaches the world
Over the years, the world of hydrocarbon exploration and production has learnt a lot from the Groningen field. In 1959 no one had attempted to exploit such a giant field, so Groningen was at the forefront of technological innovation, which continues to this day. Seismic developments in the 70's and 80's allowed better field delineation, improving fault depiction and impacting on volume assessments, while later seismic developments in the 1990's gave enhanced imaging below the salt, and superior prediction of reservoir properties. After 50 years of production, the integration of the latest technologies in all subsurface disciplines is an essential part of current production strategy and future field development plans.
The use of extended reach wells from cluster points was pioneered at Groningen, a technology that has spread rapidly, with wells as long as 11km in use in the Caspian. Similarly, new liquefaction techniques and the use of larger, more carbon efficient LNG ships has made the fuel more useful and affordable throughout the world.
It was realised quite early in the development of the Groningen field that reservoir faults are an important factor In productivity. These can restrict gas flow to a certain extent, but in Groningen this only leads to a small reduction in production. The resulting compartmentalisation, however, has an effect on pressure, and blocks with reduced pressure need to be developed with a dedicated well to ensure maximum recovery. Improved seismic is helping identify and exploit all parts of the field in this way, while the powerful compressors pioneered by NAM to help compensate for declining field pressure have been used in similar fields worldwide.
Other more political and philosophical lessons can also be drawn from the Groningen experience. The decision to conserve the gas in Groningen while developing smaller fields will allow several generations to enjoy the benefits of a plentiful and secure energy supply. A longer time frame for exploitation has allowed technology and innovation to keep ahead of production, so the maximum possible recovery will be achieved. As interest in alternative hydrocarbon sources develops, there is evidence that heavy oil and tight gas may also be present in or below the Groningen reservoirs, so an existing modern infrastructure will facilitate the extraction of these.
The first well actually drilled on the Groningen Field stopped at the top of the Rotliegend Formation and was considered a failure. Not until it was deepened a few years later did geologists realise that it was the key to one of the largest gas fields ever found. Thus, as ExxonMobil CEO Rex Tillerson pointed out at the conference marking the 50th anniversary of this remarkable discovery: "even at the dawn of its development the Groningen Field offered our industry a lesson - never underestimate the extent of the world's energy endowment."