RESERVES GROWTH: Geology, Technology, Economics, OGJ SPECIAL Technology Pushes Reserves 'Crunch' Date Back In Time

N.J. Smith, G.H. Robinson
Smith Rea Energy Associates Ltd.
London

It is not within the scope of this article to attempt any systematic investigation of these exercises.

As a generalization, it would appear that the "crunch" date has tended to recede in time with successive estimates. Perhaps one of the reasons for this is the lack of clarity about the distinction between technical resources and commercially recoverable reserves, notwithstanding the efforts of bodies as diverse as the Society of Petroleum Engineers and the Securities & Exchange Commission, seeking to bring precision to a vital but inevitably imprecise issue.

This is well illustrated by reference to recent revisiting of the Hubbert Curve. At least as far as the U.S. is concerned, this would appear to be one of the more credible models for predicting the ultimate level of discovered resources and hence domestic production. For the rest of the world there appears to be evidence that the reserves peak has been moving to the right: i.e., into the future, which is perhaps readily understandable in the light of the intensity of exploration and production applied in the U.S. when compared with other major regions.

It is interesting to note that recent work on the U.S. domestic Hubbert Curve has begun explicitly to recognize that the decline in U.S. production is likely to be less precipitous than originally forecast, due to technologies such as enhanced oil recovery (EOR) increasing the recovery to resource ratio.1 The same effect is also bound to be seen on a global scale. It has recently been claimed that "on a global scale, increasing the recovery rate by 1% means getting an extra 2 or 3 years of consumption.^"2

Published estimates

Anyone examining regularly published reserves estimates must be struck by the well established recent tendency for reserves of both oil and gas, particularly gas, to grow as fast as or faster than annual production. (For the purposes of this article, estimates produced annually for proven reserves by British Petroleum Co. plc are used for illustration.³) Figs. 1[45690 bytes] and 2 [46566 bytes] show the reserves/production ratio figures plotted against production for oil and for gas.

It will be seen that the general tendency has been for both remaining proven reserves and production to increase. The blip during the oil production crisis period is an interesting illustration of the effect of price on both reserves and production. To define proven reserves in the absence of a price reference base makes little sense. Those familiar with the "ceiling test" will need no reminder of this.

The definition of "proven reserves" adopted by BP is "generally taken to be those quantities which geological and engineering information indicates with reasonable certainty can be recovered in the future from known reservoirs under existing economic and operating conditions."

The cynic might claim that such a definition lends itself easily to interpretation as "political reserves." Major oil companies themselves are often accused of "managing" reserves disclosure for the benefit of stock exchange analysts, while the large growth in the published reserves of, for instance, Venezuela, Saudi Arabia, or Mexico may have more to do with international credit ratings and market power machismo than objective reality.

Nevertheless, it would be wrong to attempt totally to "rubbish" a form of statistical presentation which underlies so much government and corporate planning. There clearly are objective realities somewhere. Among these is the fact that growth of initially recoverable reserves depends on two factors:

• The discovery rate, and
• The revision to reserves in discovered fields.

Evidence from the annual Petroconsultants publication "Petroleum Trends 1996" suggests that the contribution from new discoveries may be on a declining trend, much as predicted by the Hubbert Curve.⁴ Nevertheless, the authors use the word "may" because of their own exposure to deepwater exploration, which remains in early infancy. What is clear is that reserves revision has played a major and perhaps increasing role in the growth of proven reserves suggested by reference to BP's work.

Growth with time

The contribution to these two sources of growth in ultimately recoverable reserves can be illustrated by reference to the situation in the Northwest European Continental Shelf (NECS). Here the national governments have for many years published national reserves estimates calculated on a broadly comparable base and reflecting the evolution of what is now seen as a mixture of mature and frontier theatres.

Continued activity depends on reserves replacement as much for a province as for a company. Initially recoverable reserves on the NECS, for example, have continued to enjoy upward revision as shown in Fig. 3 [44835 bytes] for the U.K.

Some of the reserves growth is still from genuinely new discoveries, but much more arises from a recognition that earlier discoveries previously regarded as uneconomic can now be developed profitably or from revisions to the recoverable reserves of fields being developed or already in production. This last factor is illustrated in Table 1 [31437 bytes], for Norway, and Fig. 4 [45903 bytes], which shows how the initial estimates of recoverable reserves have grown over the years for one particular North Sea giant-Forties. Further increases in Forties reserves are widely anticipated.

The fact that once hydrocarbons have been proved in a basin or a field, the general-though certainly not the invariable-tendency is for the reserves estimates to grow with time, is not a new insight and begs the question of reserves definition. It is often attributed to better reservoir knowledge overcoming the natural caution as depletion proceeds.

However, examination of actual North Sea case studies leads to the general conclusion that more fundamental technological forces are also at work. These forces are not only leading to the identification of reserves which would not otherwise have been located, but, perhaps more importantly, are making possible the economic recovery of known reserves formerly sub-economic at the going price.

It should be said here and now that it is often the use of technological advances in combination which renders the previously impossible, possible.

The technology drivers

It is not our intention to attempt a "blow by blow" review of all the developments contributing to these changes. A limited range of examples will, we hope, prove the point.

Geoscience

Geoscience is now seen as embracing a range of formerly separate disciplines, such as geology, geophysics, geochemistry, petrophysics, and reservoir engineering, which have become closely integrated among themselves and been revolutionized over the last decade by the prodigious progress of information technology.

Without this progress-particularly in the area of 3D seismic-there would have been fewer North Sea discoveries, and those which were made would have been less well delineated prior to development. Moreover, 3D seismic has also guided improved recovery within existing fields by facilitating accurate infill drilling. The arrival of 4D seismic is now bringing with it the promise of better reservoir management, and thus increased and lower cost recovery.

There is no doubt that, although pressure-enhancing production techniques such as downhole pumps and gas lift have also been important, improved geoscience has played its part in boosting recoverable reserves at Forties and indeed elsewhere.

New drilling technologies

After many years of only slow change, drilling technology has over the past decade experienced rapid technical progress thanks to the parallel development of a number of separate enabling techniques which, taken together, have released many former constraints.

The outcomes are commonly described in terms of extended reach drilling or horizontal drilling. The former has permitted the use of existing facilities to tap the outer edge of reservoirs or entirely separate reservoirs up to 10 km from the drilling site. This advance has not only been a major factor in reducing the number of platforms required to exploit very large fields (e.g., Britannia), with substantial economic gains, but also allowed the depletion of small accumulations which would not have even supported the modest cost of a subsea well completion and tie-back. Deveron was an early example and Beinn a more recent.

The effects of horizontal (or perhaps better parallel) drilling have been even more fundamental. Many reservoirs cannot be drained economically by vertical or normally deviated wells: for example, those with thin or fractured pay zones, low energy, high viscosity fluids, or generally poor flow characteristics. Before horizontal drilling became feasible, if such reservoirs were exploited at all, the recovery was low; more typically, development did not take place.

When coupled with geoscience innovations which allow pay zones to be identified and tracked and such developments as multilateral completions and downhole pressure boosting, the prospect of economically developing an otherwise low productivity or even sterile reservoir with a highly specific and cost-effective drainage plan has arrived. The results have been little short of spectacular on the NECS, whether for old or new fields.

As an example of the former, the Danish authorities have stated that horizontal drilling, when combined with water injection, has increased the recoverable reserves of the old Dan field by nearly 160 million bbl and that in the sector as a whole horizontal drilling has increased total reserves by twice as much, an increment of over 20% to the national reserves base.⁶ They also noted that the production of a horizontal well is typically five or six times that of a conventional well, very much greater than the increased cost.

Where new fields are concerned, the examples are numerous. Certainly, it is already evident that horizontal drilling will be critical to the development of West of Shetland fields such as Foinaven, Schiehallion, and Clair.

However, to date the most spectacular example has been in Norway, where Troll West oil field-once considered to be unexploitable-now looks set to yield over 1 billion bbl. Its development provides a very good example of how the conjuncture of apparently unrelated technological developments can facilitate a field's exploitation, involving as it also does a concrete floating production facility and multiple subsea completions. As a result of the most recent reserves upgrade, a second large floating production system has been ordered.

It would be possible to go on with many other examples. Last year Smith Rea research concluded that between 1991 and 1995 alone the new drilling technologies were responsible for adding about 4.8 billion bbl to the commercial oil reserves of the NECS, perhaps representing a capital value for the oil industry, governments, and supply industry combined of a staggering $30-40 billion.⁷ It was considered that 40% of this gain represented the creation of new reserves by making possible the development of previously uncommercial discoveries.

The national distribution of these reserves gains is shown in Fig. 5 [42503 bytes]. Over and above these reserve gains, capital savings of $1.5 billion or so were identified. These figures take no account of gas or the values arising from the deferred abandonment of old fields.

Were the experience of the NECS to be replicated on a global basis, the reserves increment due to drilling advances could be as much as 350 billion bbl. It may take decades for such figures to be recognized in published reserves.

Subsea facilities

Fifteen years ago, subsea completions were seen primarily as an adjunct of floating production systems. Ten years ago, floating production in the NECS was in the doldrums, and subsea completions were seen mainly in the context of tie-backs to fixed platforms.

There was, however, a growing confidence in subsea equipment, an increase in the distance over which multiphase fluids could be transported, and in particular the emergence of spare processing capacity on platforms and in pipelines as field productions fell. The result was a low cost development route for small fields which proved economically very robust in the depressed price conditions following the 1986 price collapse.

An additional benefit arose from the incremental revenues to the host infrastructure. By deferring the economic cut-off, the depletion of reserves already under production could be more thorough. Large numbers of subsea tie-backs are already in existence, ranging in size from over 190 million bbl (e.g., Vigdis) to less than 4 million bbl (e.g., Hamish).

With unboosted tie-back now possible for oil in excess of 20 km (and much more for gas), the number of subsea completions will continue to rise. The current moves into deep water and the associated growing dependence on floating production systems will give a further boost to seabed completions, now increasingly diverless in character.

We are already close to the point when the majority of new NECS fields will be at least in part subsea.

Fixed platforms

There have been progressive advances too in the most traditional of offshore development routes, with the arrival of lighter and cheaper fixed platform structures using new design and topside equipment concepts and often designed to be lightly or not normally manned.

The latter type of development has been particularly notable in the North Sea's Southern Gas basin. Resultant declines in both capital and operating costs have been reserves-enhancing, in some cases providing hosts for future subsea or extended reach satellites.

Floating production

Such developments have become overshadowed by the abrupt rise of the floating production system over the last 3-4 years. What is more, the monohull floating production, storage, and offloading system (FPSO) has simultaneously displaced the long-established semisubmersible floating production system (FPS), usually exporting through a pipeline, as the preferred NECS system.

The entrance of the FPSO has now reached Brazil, where Petrobras has for long led the way in deepwater production, combining diverless subsea completions with semisubmersible FPSs.

Whereas the NECS saw the birthplace of floating production systems with Hamilton's pioneering Argyll field, it took more than 10 years before the FPSO first made its appearance there in the form of the Petrojarl 1, which arrived in 1986. Yet its principal advantage, that of integral oil storage, would always have been apparent since early FPSs were notorious for down-time arising from offshore loading difficulties. In other parts of the world the introduction of the FPSO with its integral storage closely followed development of Argyll itself.

The reason for the delay on the NECS appears to have been the need for perfection of a number of enabling technologies (Table 2) [31757 bytes]. As to why Petrojarl 1 had to wait for another 5 years for its first employment in a production role off the U.K. is more difficult to explain. Perhaps it required that period of experience plus the construction of BP's Seillean to provide sufficient confidence in the sea-keeping qualities of the harsh environment monohull.

More probably, after the successful depletion of the Angus field by Petrojarl 1 it was the advocacy of an operator, in this case Amerada Hess, which swung industry opinion in favor of the FPSO.

As to the reasons for the general swing towards floating production and offshore loading, although the technical arguments are strong and well rehearsed, we must admit that in this case their advantages in terms of changing commercial attitudes are at least as important (Table 3) [43236 bytes].

It is the combination of the factors listed in Tables 2 and 3 with recent advances in geoscience and drilling technology which has allowed the conversion into commercial reserves of deepwater reservoirs west of Shetland and elsewhere. Otherwise even when discovered, they would have remained as merely "technical" resources.

More gains?

The foregoing analysis suggests that the increase in commercially recoverable reserves in what has been the most dynamic of regions outside the Organization of Petroleum Exporting Countries has allowed production to continue to increase "just in time" to inhibit the exercise of undue market power by the OPEC states. While improved exploration techniques played a not insignificant part, they have had to fight a tendency for the average size of new discoveries in a given area to fall with time.

The more substantive increases in reserves have come from increasing the recovery factors in fields under production. Perhaps in the long term the most significant of all have come from the conversion of otherwise merely technical resources to commercial reserves, where development drilling and production technology have been the keys.

Taking these effects and extrapolating them to other non-OPEC regions (notwithstanding the fact that globally the main effects of extrapolation will be found within OPEC), they have clearly had beneficial macroeconomic effects on the Western economies. The question inevitably arises as to whether further technological progress, plus the wider application of the current state-of-the-art, can continue to hold OPEC market power at bay.

So significant is this issue seen in the context of security of supply for the European Union that Smith Rea Energy Associates, in association with a number of other European centers of expertise, has recently been awarded a contract by the European Commission to form such a judgment, both with respect to the near and long terms.

While this work is only in its early stages, it already suggests that both the ability to identify hydrocarbon traps and subsequently to achieve higher economic recovery will continue to improve. When coupled with the progressive removal of deepwater exploration and production constraints, the indications are that "just-in-time" increments to non-OPEC reserves will continue to materialize for many years.

References

1. Ivanhoe, L.F., "Updated Hubbert Curves Analyse World Oil Supply," World Oil, November 1996.
2. Appert, Oliver, "Oil and Gas Supply in the Next Millenium: Technical Challenges and Opportunities for Europe," 5th European Oil & Gas Symposium, November 1996.
3. Statistical Review of World Energy, BP, London.
4. World Petroleum Trends (WPT) 1996, Petroconsultants, London.
5. Norwegian Petroleum Directorate, Stavanger, Annual Report, 1992.
6. Danish Energy Agency, Copenhagen, Annual Reports.
7. "The Economic Implications of New Drilling Technologies, 1996, Smith Rea Energy Aassociates, Canterbury, U.K.

The Authors