Firm Sees Value After 5 Years of Using the Petroleum Resources Management System

The implementation of the PRMS has contributed significantly to the understanding of the hydrocarbon-maturation process in the Netherlands.

Fig. 2—Small-field reserves after production and added reserves.

The Petroleum Resources Management System (PRMS) reserves-reporting system was adopted by EBN in 2009. At that time, a new PRMS project database was developed. The implementation of the PRMS has contributed significantly to the understanding of the hydrocarbon-maturation process in the Netherlands. It has proved to be a valuable system for hydrocarbon-maturation analysis and reporting and provides insight within the current and future activities of the Dutch exporation-and-production industry.


The Netherlands is part of the southern North Sea Permian basin. The country counts more than 500 oil and gas fields. Most of the fields are gas bearing; less than 50 fields contain oil. The number of onshore and offshore fields is roughly comparable, although slightly in favor of offshore.

The Dutch hydrocarbon region is considered mature. The production of the small fields is declining. As of 2014, more than 80 fields have ceased production. Approximately two-thirds have reached the tail-end phase of their production life, which is defined as having produced more than 85% of their expected ultimate recovery.

New hydrocarbon accumulations are still being discovered, an average of 10 fields per year over the last 5 years. The annual number of exploration and appraisal wells varies between 10 and 20. The annual amount of production wells (infill and development) varies between 20 and 40. In the Netherlands, the overall investments have remained fairly stable since 2005. A total of EUR 1 billion to 1.2 billion per year is spent on the exploration and development of small fields.

EBN is the state participant in exploration and production licenses in the Netherlands. In the Dutch Mining Act, Article 82, EBN is the designated company of which all shares are, directly or indirectly, held by the state in the interest of efficient exploration and production, systematic management, and optimal disposal of hydrocarbons. The state share is either 40 or 50% in all licenses on a nonoperating-venture (NOV) basis. This makes EBN the largest upstream gas owner (nonoperated) in the Netherlands.

The new PRMS introduced in 2007 offered a great opportunity to classify and quantify the full hydrocarbon potential of the Netherlands systematically. It has contributed significantly to improving and streamlining EBN’s business processes and its plans to stimulate the future national hydrocarbon maturation. Currently, EBN has its focus on developing the upside of the contingent and prospective resource base. Various projects have been initiated to enhance the maturation of the exploration, the tight gas, and the mature-field portfolios.

PRMS Database

EBN largely follows the PRMS classification system of 2007, using guidelines from 2011. For practical purposes and effective communication, the project maturity subclasses [resource classes (RCs)] on the vertical axis of the system have been numbered (Fig. 1). The classification of the subclasses is comparable to PRMS’, apart from the “Justified for Development” category (RC=3). Here, EBN has a taken a conservative approach. A project classifies as RC=3 only when the project is expected to have its final investment decision (FID) in the next year according to the approved work program and budget (WP&B). In case the FID is announced in the WP&B in a time frame of 2 years or more, the project ranks as RC≥4.

Fig. 1—Project maturity subclass numbering and growth of the PRMS database.

As of 2008, EBN has gradually filled the PRMS database. In 2008, before implementation of PRMS, the reserves-reporting system contained mainly RC=1, with only a few new projects in the construction phase (RC=2). In 2009, all projects in the reserves classes were added. In 2010, a start was made to inventory the contingent resources, and this was completed in 2012. In 2013, prospective resources were completed up to the “Lead” subclass (RC=9). The database is frozen at 31 December of every year to allow the reproduction of annual reserves and resources. As of 31 December 2013, more than 1,300 projects that have a production forecast, including those with no further activity, have been stored.

As an NOV partner, EBN has access to various sources of information to update the status of the projects in the PRMS database. The information sources range from technical committee meetings, technical workshops with the operators and partners, monthly reports of production and projects, and new insights from post-drill results.

In addition, EBN is actively adding projects in the “Lead” category (RC=9) with the in-house interpretation of a recently acquired 7500-km2 offshore 3D-seismic survey.

With more than 1,300 projects, maintaining and updating the database is a significant but worthwhile task. Updating and reporting is accomplished by reservoir engineers, facility engineers, geologists, and geophysicists in EBN. The value added from PRMS is in the multiple years of reporting and analysis.

Project Attributes

The authors expanded the PRMS system by adding various attributes to each project. Attributes can have a relation to

  • Project phasing (e.g., exploration, appraisal, development, production, end of field life, or stranded)
  • Reservoir type (e.g., conventional, tight gas, shale gas, or shallow gas)
  • Project type (e.g., an infill well, a compression project, or a deliquefication project)

For each project, the authors also include project timing, which has an initial estimate, a latest estimate, and actual realization dates for when a project is supposed to or actually does mature from one RC to the next. The project timing data allow for prediction of the expected maturation for the running year as well as for the long-term future and allow for monitoring the actual performance against the prediction.


Historical Maturation of Reserves on Portfolio Level. Fig. 2 above shows the small-field reserves including production and reserves additions starting on 31 December 2007 and ending on 31 December 2013. After an initial increase in 2008–09, followed by a sharp decline between 2009 and 2011, the decrease in reserves has leveled off in recent years. The changes in offshore and onshore reserves are attributable to production, maturing contingent and prospective resources into reserves, definition of new projects with reserves, and updating the ultimate-recovery estimates for existing projects. Although the relative importance of these four factors varies from year to year, maturing existing resources and approval of new projects are the most important.

Historical Maturation of Reserves on Operator Level. The average annual reserves maturation per operator for 2007–13 shows that there is a wide spread in the average annual reserves maturation per operator and that only a few operators are responsible for the majority of the maturation. However, one should not conclude that a high or a low annual maturation value is, by definition, good or bad because annual production level per operator also must be taken into account. The ratio of annual maturation to production (i.e., reserves replacement) is a much better indicator for good or bad maturation levels.

Lifetime Expectancy on Operator Level. Fig. 3 shows the ratio of the reserves or resources of individual operators to annual operator production in 2013. The figure shows the reserves and risked resources. “Risked resources” means that the contingent resources are risked with a probability of maturation, while the prospective resources are risked with a probability of success and a probability of maturation. The risked-resource volumes are a measure of the most likely potential in the resource base. The unrisked resources, without the probability of maturation, are illustrative of the upside potential in the resource base.

Fig. 3—Unrisked and risked LTE based on manipulated operator data.

Fig. 3 shows that a number of operators have a lifetime expectancy (LTE) of less than 5 years, on the basis of their reserves base only. Some have an LTE between 5 and 10 years, and only a few have an LTE greater than 10 years. Operator 3 has no production yet, so it is impossible to calculate the LTE. An LTE below 5 years is an indication of a very unhealthy reserves base. Those operators need to invest immediately to mature contingent and prospective resources into reserves or they will most likely see a strong decline in their current production levels.

On their total-resource base—reserves and risked resources—the majority of operators have a risked LTE greater than 10 years. A few have an LTE between 5 and 10 years, and one is below 5 years. The operators with an LTE below 10 years, and particularly the one with the LTE below 5 years, are at risk and need to improve their reserves and resource base or they most likely will see a strong decline in their current production levels. Operators with an LTE greater than 20 years need to increase their current production levels or increase their exploration-drilling effort, preferably both, to produce their resources within an acceptable time frame. Operator 13, with the highest average annual maturation, has a low LTE because that operator also has a very high annual-production level. To maintain that high production level, Operator 13 needs to expand its reserves and resource base. Operator 1, with the lowest average annual maturation, has an LTE comparable with that of Operator 13, on the basis of reserves only. This is caused by the lower annual-production level of Operator 1. Operator 1 has a significant resource base, as can be seen from its LTE when it is based on risked resources only, which makes it even more unclear why it has a negative average annual maturation.

Comparing the LTE graph for various reporting years will show whether the overall reserves-and-resource base per operator grows or shrinks and whether contingent and prospective resources mature to reserves. Changes in annual-production levels will, of course, have an effect on that analysis.


PRMS has been implemented successfully in EBN. The implementation of PRMS improved EBN’s business processes, and it is highly recommended for

  • Monitoring and forecasting hydrocarbon maturation and resource replacement
  • Reporting of reserves and resources
  • Benchmarking the operator portfolios

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 170885, “The Value Added After 5 Years of SPE-PRMS,” by Eric Kreft, SPE, Raymond Godderij, SPE, and Berend Scheffers, SPE, EBN, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands, 27–29 October. The paper has not been peer reviewed.