Modeling the Oil & Gas Production in Norway

Published on

September 3, 2018


Article by

Omar Chique

The production of oil & gas in Norway in the 1975-2014 period is simulated. A geological and economic structure deemed responsible for this supply behavior is presented. Historical data (in million Boe) from the Norwegian Petroleum Directorate (NPD) is used as a reference.

In figure 1, production peaked in 2002. At that moment, the net production capacity rate (figure 3) is zero. That is, the capacity loss gets higher than new production capacity in that year. Notice that oil prices increased afterward, leading to lower than potential revenues.

Figure 2 depicts the structure responsible for this supply behavior. Investment pressure pushes new projects. The higher the pressure, more projects step up the portfolio. These projects become new production capacity after being constructed. This process enables, or ‘develops’ reserves. Upstream cost tends to slow down, as oil firms favor new projects that can use existing infrastructure. Without previous infrastructure, the upstream cost tends to be higher. They aim to extend the oil fields producing time spans. They achieve this because costs for modifications and new investments can be shared (NPD, 2013). Also, oil firms obtain new knowledge when developing results, enhancing productivity and reducing development costs.

Firms assess projects profits based on oil price and breakeven costs. The higher the ratio between the two, there may be more incentives to pursue projects. This creates a pressure to invest, which accumulates over time; and which may be released based on various factors. First, willingness to invest may depend on the assessment of business context made by investors. Second, oil firms may decide to slow down the reserves development rhythm, or it could be mandated by local authorities, owners of the oil crude ‘resource’. Third, projects may exist in a country that belongs to OPEC, in which case, it might be recommended not to pursue new projects for some time. Fourth, the producer may decide that it is not in its best interest to increase its market share in a local or global market. Fifth, the oil firm may be partially banned to trade its oil in the market, as was the case in Iran, recently.

The higher the investment pressure, further adjustments to portfolio and construction are made. This creates a reinforcing major loop which adds projects, when investment pressure raises, leading to higher production. However, it also tends to reinforce a declining production when investment pressure drops. The latter may be curtailed by the oil price to breakeven ratio. Hence, geology matters. It is hard for oil firms to boost production if the project’s development cost is high. This may be due to the nature of the oilfield involved: or the quality of the oil crude or the distance of the oil field to existing capacity to store and transport the extracted volumes. Operating costs may be high too. Extraction techniques may be outdated, or the oil firm may have more employees than required. The latter occurs in mismanaged National Oil Companies (NOC’s). All these factors boost the upstream cost per barrel, shrinking the oil price to breakeven cost ratio.

A major investing balancing loop tends to weaken the production raise cycle examined. Since oil firms tend to extract the low-cost barrels first, operating costs surge as time elapses. Hence upstream cost goes up as oil fields are depleted. This lowers the oil price to breakeven cost ratio. This leads to lower investment pressure, smaller projects, capacity, and production; leaving the oil price as a key factor. It may rise the oil price to breakeven cost ratio and enable projects.

Chique, O. (2016) Dynamic Performance Management of Upstream Oil Companies, Ph.D. dissertation, University of Palermo, Italy

NPD Norwegian Petroleum Directorate (2013), Norway

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