Benchmarking Oil and Gas Field Recovery Targets and Investment in Norway

Benchmarking Oil and Gas Field Recovery Targets and Investment in Norway

2nd August 2017

Introduction and Database

Efficiently defining production targets and the required operational investments to realise them can be aided by drawing on regional and analogue databases of field type and production performance, as a means of setting appropriate benchmarks and establishing examples of “best practice”. 

The Norwegian Continental Shelf is an ideal testing ground to examine models of long term performance of oil and gas field operations, gross investment and actual and future estimated recoveries. It has a long history of discovery, growth and maturity of fields in a diverse set of oil and gas plays, and study is aided by ready access to the comprehensive information set provided by the Norwegian Petroleum Directorate (NPD) through its “factpages” and associated website (1)

GCA has extracted parts of this public database for 109 fields Norway-wide (Figure 1), and augmented it with certain additional, separate data tables from its own non-proprietary resources, in order to create a working database for interrogating field performance. GCA has then undertaken a reconnaissance investigation, focussing on the North Viking Graben area (Figure 1), in order to define a range of performance measures, including hydrocarbon recovery targets and their achievement, and on the effectiveness of reported investments.

Figure 1: Location Map, Norwegian North Viking Graben Oil Fields

Norwegian Oil and Gas Fields: Hydrocarbon Recovery and Recovery Targets

In overview, the GCA database records hydrocarbons in-place, actual production, Estimated Ultimate Recovery (EUR) volumes expected (2) and the associated financial investments. Subsets of field data have been extracted according to reservoir age, reservoir type (clastics v. carbonates), dominant fluid type and geological province/play.

Looking Norway-wide, based on expected recoveries and reported volumes of hydrocarbons in-place, “target” recovery factors that might be anticipated for gas fields (Figure 2) range from 26% to 87% in both Mesozoic and Tertiary sandstone targets (averaging 58% and 60% respectively). Those for oil fields (Figure 3) range from 3% to 73% in the Mesozoic and Tertiary sandstones (averaging 41% in both cases). Recoveries from Upper Cretaceous to Paleocene chalks are less, ranging between 12% and 55% and averaging 33%.

Figure 2: Expected Recovery Factors, Norwegian Gas Fields

Figure 3: Expected Recovery Factors, Norwegian Oil Fields

There are clearly outliers in these ranges of recoveries, but the wide range of recovery factors is striking and reflects the variations in geology and, to a lesser extent, fluid properties and development plans. What controls the performance of “typical” fields? Are predicted recoveries realistic in terms of the geology and engineering aspects of the fields? How do neighbours within the same province compare? And does the performance of fields to date suggest that these targets will be realised efficiently and effectively? To this end GCA has extracted subsets of data and compared fields in each of the major geological provinces and plays in terms of the historical growth of actual recovery factor and its progress towards its target.

Although the approach lends itself to all plays, this exercise has focussed on the oil fields, where there are a greater number of examples within each of the play groups, and where there is commensurately greater diversity of geology and production experience.

In terms of benchmarking overall performance, it is the older, larger fields that have been able to support a programme of long term investment that are predicted to achieve and/or have attained the highest recovery factors. These include Ula in the Central Graben (recovery to date 43%, expected to achieve 48%) Statfjord in the North Viking Graben (recovery to date 67%, expected 69%) and Draugen in Mid Norway (recovery to date 61%, expected 64%). It is clear that some more recent discoveries, which are smaller and more complex, will struggle to make these levels within their economic limits (Figure 4).

Figure 4: Expected Recovery Factors of Oil Fields by Size and Age

North Viking Graben

Whilst local geological and operational considerations may be paramount, some further more detailed conclusions can be tentatively drawn, and a number of comparisons can be made. For the purposes of this brief article, focus is on just one group of Jurassic plays in the North Viking Graben. For presentation clarity, the fields are grouped into three areas: i) Statfjord, ii) Gullfaks and iii) Oseberg (Figure 1), all with fields with comparable levels of production maturity. The bulk of the fields are reservoired in structural traps containing Middle Jurassic sandstone reservoirs of the Brent Group, with subordinate Lower and Upper Jurassic contributions, and are mostly produced by pressure depletion with combinations of water, gas and WAG injection IOR techniques.

A plot of recovery factor against time since the onset of production is presented in Figure 5. In all cases, this shows cumulative production, in oil equivalent terms, divided by the currently stated hydrocarbons-initially-in-place, again with all phases and hydrocarbon types combined. In Figure 6 the same data are shown, but where the evolving recovery factor is compared to the expected ultimate recovery factor, a ratio which thus tends towards unity at the end of field life.

Figure 5: Recovery Factor History, Norwegian North Viking Graben Oil Fields

Figure 6: Recovery Factor Ratio History, Norwegian North Viking Graben Oil Fields

Each field has its own trajectory on the graphs presented, but groupings can be recognised where fields follow similar paths. Early performance is not necessarily a guide to ultimate results, but within each group a “best-in-class” can be identified, commonly where the field is at or near its expected final value on a long, low gradient trend. It is not appropriate to over-interpret this dataset, but certain relationships are of interest. Supporting information is here drawn only from that reported in the NPD “Factpages”(1).

The three Statfjord fields (Main, Nord and Øst) stand out at the top of Figure 5. Within this group, the two smaller, later satellites (Nord and Øst) show accelerated early production where recovery achievement has been approximately 9-10 years ahead of their larger neighbour (Main) at comparable stages in their history, although water injection, active early in the field’s life, has reportedly now ceased at Statfjord Øst. Distinction is probably mostly because Statfjord being so large, was developed over several years through multiple platforms, with production gradually ramping to a plateau rate, whereas the smaller neighbours achieved a plateau rate more quickly. It is noticeable that comparing near neighbour fields with and without active intervention in the late stage shows the effect of boosting overall recovery factor with water and/or gas injection. The lower recovery factor of the Sygna Field, now producing by pressure depletion alone, compared to its neighbour at Statfjord Nord, where water injection continues, reflects a possible example of this (Figure 5).

Actual and expected ultimate recovery factors in the group of fields around Oseberg are lower in general, in part reflecting more variable reservoir quality in the Brent Group reservoirs than seen in the Statfjord area, although other factors, including those connected with fluid composition may also of course be significant. Two of the fields, Veslefrikk and Brage, are approaching their expected ultimate recovery factor, partly as a result of efficient application of WAG pressure support, not reported as the major technique at the two Oseberg satellites. In the case of the main Oseberg field, although recovery factor is high, it is still growing some way short of the expected value, suggesting significant late stage development activity is planned.

Broadly the same range of recovery performance is seen in the Gullfaks Group as in the Oseberg Group, with possible additional geological complexity being the dissection and potential compartmentalisation of the fields by normal faulting. Fields early in their history, such as Visund Sør and Gimli appear on a similar trajectory to that established by the main Gullfaks Field. The two lower achieving fields (Gullfaks Sør and Visund) are possibly explained partly by the additional complexities of normal faulting and the reported cessation of large scale active pressure support.

This overview identifies the groupings and range of field performance and offers some high level explanation. In addition to the factors identified, there may be further local complexities of structural and or reservoir geology, and other operational considerations, such as unavailability of gas, which may also pose challenges.

Financial Comparison

In financial terms, if a subset of Mesozoic oil fields with sandstone reservoirs are compared, within all geological provinces, a broad picture of investment emerges. The data are understood to comprise total capital and operating investments, made and planned.

A band of normalised investment between 300-800 NOK/m3 recoverable oil-equivalent appears to apply for the larger oil fields. The data show a much greater scatter in fields with a recoverable resource below approximately 20 x 106 m3 oil equivalent. There is no major variation with age of production start-up, although smaller developments have possibly become more financially efficient, as evidenced by Figure 7, possibly by being able to make use of existing infrastructure.

Figure 7: Normalised Total Investment Recorded, Norwegian Oil Fields


Whilst this a high level view of the data on the production performance of Norwegian oil and gas fields, it allows us to observe:

    ·     the overall control of reservoir geology;

    ·     best in class targets that may be achieved;

    ·     the benefits of application of focussed IOR programmes and continued investment late in               field life; and

    ·     an approximate benchmark for optimal levels of financial investment.

GCA is active in the Norwegian oil and gas sector providing ongoing support to its clients in exploration, development and production.


(1) Contains data under the Norwegian licence for Open Government data (NLOD) distributed by the NPD.
(2) Recovery factors are based on the ultimately recoverable resources and in place volumes quoted in the NPD database. It has not been tested by GCA that the unproduced part of these equate to “reserves” in the sense strictly defined by the PRMS.


Benchmarking Oil and Gas Field Recovery Targets and Investment in Norway

Dr Nick Stronach

Senior Advisor: Geoscience -

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