Reasonable Certainty - Moving from Resources to Reserves

This is the third post in a series of three:

3. What level of proof is required to classify different categories of resources?

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TLDR shortcut, accuracy and precision are different qualities as are risk and uncertainty:

• ⁠Prospective Resources - often more precision than accuracy based on volumetric estimates from seismic and rock properties based on analogues. High risk as to whether these resources even exists and high uncertainty as to their scale • ⁠Contingent Resources - higher accuracy based on actual data from a well and tied to volumetric estimates. Lower risk as to the existence of the resources than prospective resources but uncertainty remains as to timing or viability of development. • ⁠Reserves - not necessarily greater accuracy or less uncertainty as to the estimate of volume than contingent resources but reasonable certainty of commercial production

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The history of reserves estimation and the journey towards the standard of “reasonable certainty” for classifying resources as proven reserves begins with the emergence of reserves disclosure more than a century ago.

• During World War 1 the National Petroleum War Service Committee (NPWSC) that was later reformed into the American Petroleum Institute (API) gathered information on how much oil American companies possessed.
• The period of oversupply after WW1 led to prorationing based on companies’ relative ability to produce. Then WW2 created a huge supply need – 6 of every 7 billion barrels used by the Allies in WW2 came from the US – and modern reservoir management practices came of age.
• World energy crises beginning in 1973 led to growing mistrust in E&P companies which resulted in widespread support in US Congress for a government managed centralized energy system - including the rules for calculating disclosed reserves.

The system used in the US today (and similar systems around the world) dates to 1978 and was more directed to US national security than financial needs. In those days, 2/3rds of all reserves reported under these SEC rules were in the United States. 25 years later, that proportion was less than 1/5th. During the intervening period, the industry had moved from typical “one well at a time” reserves in wells producing at tens or hundreds of barrels per day and assessed based on production decline curves to an industry in which a growing share of reserves were to be found multi billion dollar developments of fields that produced tens and hundreds of thousands of barrels per day.

The stakes had risen exponentially. It used to be the case that proved reserves were assigned only to those wells where hydrocarbons had flowed to surface. So called “behind pipe” reserves could only be counted if such zones had been shown to produce successfully in nearby wells. Potential infill drilling locations could only be assigned if they were in spacing units that were adjacent to a well that was producing. Reserves associated with secondary recovery could not be considered until the secondary recovery program had been implemented and shown to work. The intent was to ensure that companies did not over-claim their proved reserves since this was what was valuable to investors and the greater concern was that any new investor should not find that they had bought shares in a company whose reserves turned out to be a sham. It seemed odd that the financial regulator would not seek to protect investors who already owned shares in companies that might be worth appreciably more than was apparent from their over-conservative reserves assessments.

The proof of the conservatism of reserves assessments was that, over time, reserves upgrades significantly outweighed reserves downgrade (more among larger oil companies than the smallest) but even there the trend was for consistent upgrades over time. In the early part of the 20th century, Shell got caught up in a scandal when it had to write off reserves that it had “booked” prematurely because it had not abided by the letter of the rule. The SEC and other national regulatory bodies re-examined the rules after realising that technology had developed to a point where the standard of “reasonable certainty” could be met in more ways than just flowing a well for a period of time. Indeed, for environmental reasons, Norwegian oil field developments were proceeding with multi-million dollar price tags without ever flowing to surface prior to production platforms being installed. Elsewhere, including the Gulf of Mexico, a similar situation of investment without well tests was developing - except this time for safety reasons following the Deepwater Horizon disaster.

A suite of new tools and integrated analyses was found to provide as much certainty as more traditional, expensive approaches had previously delivered. At the same time, companies began to focus more on the general classification of resources including those that fell short of being recognised as proved reserves because it was increasingly clear that these other resources had value even before they became reserves. So how do different methods provide degrees of certainty to investors and how deep should prospective investors dig behind the glossy “prospective resource” estimates of E&P companies?

First, it is generally true that only the drill bit can confirm whether there is oil, gas or some combination in the identified prospect. There can be direct hydrocarbon indicators (DHI) such as bright spots, flat spots etc (more easily identified with 3D than 2D seismic) but there have been countless wells where subsequent to drilling an alternative explanation for an “artifact” seen on seismic has been found. In general, DHIs are most useful and can be accepted for extending the area of an accumulation that has already been proved by drilling and tying the seismic to the well.

As an example of how reliable or unreliable seismic interpretation can be, even when tied to a prior well penetrating an oil bearing horizon, Pantheon’s Talitha well was expected to penetrate a package of shelf margin deltaic sediments that had already been penetrated in the Alkaid and Pipeline State wells and tied to a 3D seismic survey. The Talitha result was unexpected - the expected package of sands was a shale at the new well location but another package of sands that had not been expected was found which appears to have greater areal extent and more continuity between the wells. The original seismic artifact has been reinterpreted and adds to the understanding of the distribution of reservoir quality sands across the licences. Similarly, the success of the 88 Energy Merlin 1 well was thought by many to be a foregone conclusion because of DHIs (from 2D seismic data) and yet the result seems to have been that the primary targets were water saturated (low hydrocarbon saturations) while a new and unexpected sand that was not mapped has been found. In both cases the results are positive for the two companies but not what they expected prior to drilling.

The most critical transition in a resource classification framework is from resources to reserves. The gold standard for the “reasonable certainty” required for this step has long been a well that intersects net pay identified on logs which, when cased off, perforated and flow tested, delivers commercially viable flows of hydrocarbons to surface. However, as previously noted, environmental and safety regulations have prevented a number of major discovery wells from being flow tested in this way and so technology has had to come to the rescue in providing alternative means of evaluating formations and their ability to flow hydrocarbons. The relevant words from the SPE’s Petroleum Resources Management System (PRMS) are:

“To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.”

The consequence of this more flexible definition than existed in the original 1978 standards is a set of tools that measure reservoir properties that could not previously be measured and more accurately than ever before. GeodesRock provided an excellent example of NMR logging - comparing it to a Mexican Wave at a sports stadium. VAS analysis provides another perspective but best of all is a downhole formation test (RFT or Mini-DST). It is this last class of test that 88 Energy was attempting to conduct in the most prospective logged intervals in Merlin 1 (which failed because of poor hole conditions) and which they managed to gather in the less prospective (low hydrocarbon saturation) zones higher up the wellbore.

In summary, the technologies now available to assess the likelihood and certainty with which a well might flow commercially is as different today compared to four decades ago as the comparison between an MRI or CAT Scan and having to open the patient’s skull to diagnose a brain tumor!