Strict regulation of the use of associated gas and extensive monitoring by the government have helped to add value to Norwegian offshore resources which would otherwise have been lost.
Flaring of exploitable gas on the NCS must not be accepted except during brief periods of testing.
from the 10 oil commandments adopted by the parliamentary standing committee on industry in 1971.
See separate article
Since production started on the NCS in 1971, over 2 000 billion standard cubic metres (scm) of gas have been produced. Most has been exported to European markets.
A small amount has been consumed in Norway for petrochemical plants, as fuel on platforms and for transport. Strict regulation and financial incentives mean little has been flared.
More than a quarter of the gas produced has been injected back into the reservoirs to sustain their pressure and thereby contribute to improved oil recovery (IOR).
Such injection is estimated to have boosted oil and condensate recovery by about two billion barrels (320 million scm). Most of the injected gas can probably be produced and sold later.
Global flaring seen from the outer space.
In ensuring that the oil companies utilise associated gas to the maximum benefit of society, the regulations on proper use of Norwegian petroleum resources have been of paramount importance.
These specify that “burning of petroleum in excess of the quantities needed for normal operational safety shall not be allowed unless approved by the Ministry”.
The companies accordingly had to find appropriate ways of exploiting associated gas from day one. That involved piping it to market in most cases, but injection was the only option if no pipeline was available.
Associated gas from oil developments originally dominated Norwegian output of this commodity, but reserves from pure gas or gas/ condensate fields have played a steadily growing role.
Figure 1: Gross Norwegian gas production and fraction injected.
Strict regulation of gas flaring from the start, a carbon tax introduced in the early 1990s and extensive cooperation between government and industry have produced good results.
The total volume flared and vented has been remarkably low, at only about 0.16 per cent of production in 2004. And, as figure 2 shows, the trend over the past two decades is downward.
Figure 2: Gas flaring and venting, scm per scm of oil equivalent sold.
The philosophy of open access to the gas transport infrastructure adopted by Norway is very much a prerequisite for optimum use of associated gas.
As production from a field declines, spare capacity will often become available in existing processing facilities and pipelines which allows other resources to be tied in.
In some cases, this will be essential for profitable production of new fields too small to justify their own installations.
The authorities play an important role in creating and expanding transport capacity, and study alternative transport methods to ensure efficient system development.
Several of the technical solutions currently used by the Norway’s oil and gas industry reflect significant investment in research and technology development in the 1970s, 1980s and 1990s.
Major R&D programmes have addressed various IOR opportunities for Norwegian fields, including the benefits of gas injection.
With value creation on the NCS set to become more technologically demanding and knowledge-intensive, however, continued R&D efforts will be important for keeping Norway’s oil and gas industry competitive.
Injecting water and/or gas is normally necessary for achieving a high recovery factor on an oil field, and the great majority of developments on the NCS have included this in their initial plans.
Most Norwegian oil fields use waterflooding as their main recovery mechanism. For some, however, reservoir evaluations showed clearly that gas injection could yield much higher recovery.
Combined with economic evaluations, that prompted the use of gas injection as the principal recovery mechanism in these fields. Gas or water alternating gas (WAG) injection was also introduced on others as a supplement to waterflooding.
In some cases, too, the inability to export gas was a driving factor. This means gas has also been injected into fields where the effect on recovery is moderate. With very few exceptions, however, injection has had a positive impact.
Gas/condensate fields can be produced either by pressure depletion or by partial or full injection of the separated dry gas over a certain period.
In the latter case, liquid drop-out in the reservoir will be reduced and a higher fraction of the condensate content in the gas can be recovered.
A total of 595 billion scm of gas had been injected into 28 fields at 31 December 2009. About 60 per cent is concentrated in Oseberg, Statfjord and Åsgard.
Figure 3: Historical gas injection per field on the NCS.
Figure 3 shows the volume of gas injected into various fields up to 2008. A few of these have supplemented their own gas with supplies from neighbouring developments.
However, the majority have based injection on their own gas output. The same gas can also be produced and injected several times.
Figure 4: Historical and planned gas injection (based on approved plans).
Figure 4 shows both historical gas injection and forecasts based on company plans. Some 35-40 billion scm of gas have been injected annually in recent years, and this level is set to be maintained for some time.
The average future oil recovery factor for Norwegian fields, based on sanctioned oil company plans, is expected to be 46 per cent.
However, this figure is set to reach 60-70 per cent for some of the big fields, such as Oseberg and Statfjord. That reflects both successful use of gas injection and very good reservoir properties.
The NPD undertook a review in 2005 of NCS fields which have injected and/ or have plans to inject large quantities of natural gas. This study was updated in 2009.
Based on the updated review, the NPD estimated that gas injection – historical and planned – would yield two to 2.3 billion barrels of additional oil and condensate from the NCS.
In addition come higher or accelerated revenues because gas injection permits oil and condensate production to continue beyond the point when it would otherwise have declined or ceased.
Range of methods
The gas injection methods applied include non-miscible injection (as in Oseberg and Grane), miscible injection (as in the Statfjord formation on Statfjord and parts of Åsgard), gas and WAG injection in gas/ condensate fields to enhance condensate production (as in Sleipner East and parts of Åsgard).
A number of Norwegian fields, such as Snorre, Gullfaks, Statfjord and Ula, have employed WAG, which does not require such large quantities of gas. It accordingly accounts for only 10-12 per cent of annual gas injection on the NCS.
Gas injection challenges
Almost all the discoveries on the NCS hold both gas and oil or condensate. Oil fields contain associated gas and some, such as Troll, have a huge gas cap over a rather thin oil zone.
Gas/condensate fields have both gas and heavier hydrocarbon components. All of this means that recovering gas and oil or condensate cannot be handled independently.
Experience shows that the Norwegian government often applies a lengthier perspective than the oil companies, and thus wants to maximise value from the fields over a longer period.
In some cases, gas injection may be the best long-term solution, even though selling this resource to the market from day one would yield the highest short-term profit.
The effect of gas injection will decline over time. Sooner or later, it will be necessary and desirable to change the production strategy and recover the gas where it can be delivered to the market.
A case in point is Oseberg, where massive gas injection is the main recovery mechanism. Its licensees have postponed a planned blowdown of the gas cap several times, since updated studies showed that this would yield more oil.
Corresponding challenges will be faced on fields where the oil lies under a big gas cap. A key question is how long it will be profitable to keep the gas in the reservoir to maintain pressure and recover as much oil as possible.
In many cases, massive gas production would terminate oil output. One example is Troll, which has large quantities of both oil and gas. Studies show that the earlier gas is taken out of the Troll West reservoir, the less oil it will be possible to produce.
Generally speaking, many of the benefits offered by gas injection in terms of extra oil recovery may be lost if the gas is back-produced too early or too fast.