In an earlier life, while working for an adventurous Explorer and Promoter of oil and gas properties, we made what later turned out to be quite a significant discovery. After drilling a couple of wells and getting very excited, management began to plan the next road show.
I don’t know how things are today, but back in those days, a road show involved a mixture of hard(ish) facts, in the form of audited reserves and financials, and softer, enthusiastic geotechnical ‘promotion’ of a prospect’s potential or a field’s possible future size. This was referred to as ‘ramping’ the prospect!
Needless to say, as the same audience attended a lot of road shows, and to a large extent had heard it all before, there was a lot of pressure on to present ‘official’ audited reserves rather than to have to resort to arm waving. This meant calling in the Consultants! We pulled out all our seismic maps showing the stratigraphic play extending over the horizon. We explained the regional geology and the likelihood of a huge extent of the reservoir sweet spot. And so on.
But our arm waving was to no avail. What did the Consultants do? They applied the rules. Our bookable ‘reserves’ were limited to tiny circles drafted around the wells—as demonstrated by well tests. The result was that the road show went ahead (quite successfully as it turned out) and we got on with the drilling program. And no, the field did not go ‘over the horizon’ but it was a company-maker none the less.
The early experience led me to understand that the US Securities and Exchange Commission (SEC), which wrote ‘the rules’ that our Consultants dutifully applied, was of an exceptionally conservative disposition. To book reserves, you really had to ‘prove,’ as far as such things can be proved, that they were there—with wells and well tests. No seismic interpolation, no geological ‘romance,’ no arm waving. The SEC wanted ‘certainty.’
In the subsequent years, a lot has happened in the industry. People started to use 3D seismic, not just to map reserves, but, with time-lapse, to visualize actual production as it was happening. Seismics was capable of producing pretty unequivocal direct hydrocarbon indicators. Not exactly a well test—but certainly a demonstrable interpolation technique—one that ought to provide a promoter with more than just a little circle of proven reserves around a discovery.
Indeed, industry, particularly the Society of Petroleum Engineers, was engaged in a decade-long lobbying effort with the SEC for it to update its stuffy old requirements and allow for seismic to be used in reserve estimation. Now, after years of deliberation, the SEC has revised its reserves reporting rules which come into effect on Jan 1st 2010.
At this month’s SPE Annual Technical Conference and Exhibition, I attended a talk by John Lee* (Texas A&M) who outlined how the rules address a very different situation to that which prevailed when the previous guidelines were introduced back in 1978. Lee noted that since then, ‘technology and markets have changed and new resources like bitumen are important.’ Reserves categories have been revised, the ‘certainty’ criterion I mentioned above has been relaxed from ‘absolute’ to ‘reasonable.’ But most importantly, industry’s lobbying has been successful and the SEC has shifted from its conservative treatment of how reserves are evaluated.
Not only do the new rules allow for the use of 3D seismic in reservoir delineation and reserves reporting, they go further, allowing as yet unknown techniques and even ‘proprietary’ technology. Such novel technology does not even have to be disclosed to the SEC, whose position has changed from prescription (a well plus a well test or nothing) to, as Woody Allen might say, ‘whatever works.’
Reflecting on these presentations, I was struck by how the new SEC rules actually go beyond industry’s initial lobbying—for 3D seismic to be considered as a proving technology. In the future, a company turning to the auditors for validation of its reserves might be able to go along with say some new fangled electromagnetic survey of reservoir extent, or perhaps the low power ‘invisible light’ method we came across at the Amsterdam EAGE.
Alternatively, ‘proprietary’ seismic imaging techniques that turn subsalt synclines to structures may be trotted out. There is, after all, a lot of ‘stuff’ in geophysics that is on the borderline between science and fantasy.
The problem with all this is that it makes the auditor/regulator’s job almost impossible. Instead of having a select number of experts with skills in a recognized discipline, we are expecting them to be fluent in multiple techniques, some of which will be valid in one place and totally inappropriate in another.
Interestingly for those involved in oil country data, this places an increasing burden on traceability of the decision making process. As reserves are booked with reference to heterogeneous workflows, the onus on capture and traceability rises significantly.
How did we get here? Well the new rules may be coming in in 2010 but they have been a long time in preparation. My impression is that as the industry was pushing for specific upgrades to the rules, the regulator’s position was shifting. This was the time when folks were advocating ‘deregulation,’ or at least that regulation should be done with ‘a light hand.’ So instead of just adding to the prescription with say 3D seismic, the regulator seems to have thrown in the towel. All of which has an uncomfortable, pre-Lehman Bros. air to it!
* SPE 123793, Modernization of the SEC Oil and Gas Reserves Reporting Requirements. W.J. Lee, Texas A&M.
This article originally appeared in Oil IT Journal 2009 Issue # 10.
For more information or to comment on this topic email here.