Oil and gas reserves and resource quantification

[1] As with other mineral resource estimation, detailed classification schemes have been devised by industry specialists to quantify volumes of oil and gas accumulated underground (known as subsurface).

These schemes provide management and investors with the means to make quantitative and relative comparisons between assets,[a] before underwriting the significant cost of exploring for, developing and extracting those accumulations.

[2] Classification schemes are used to categorize the uncertainty in volume estimates of the recoverable oil and gas and the chance that they exist in reality (or risk that they do not) depending on the resource maturity.

Resources are re-classified as reserves following appraisal, at the point when a sufficient accumulation of commercial oil and/or gas are proven by drilling, with authorized and funded development plans to begin production within a recommended five years.

All reserve and resource estimates involve uncertainty in volume estimates (expressed below as Low, Mid or High uncertainty), as well as a risk or chance to exist in reality,[g] depending on the level of appraisal or resource maturity that governs the amount of reliable geologic and engineering data available and the interpretation of those data.

[h] Estimating and monitoring of reserves provides an insight into, for example, a company's future production and a country's oil & gas supply potential.

Contingent and prospective resource estimates are much more speculative and are not booked with the same degree of rigor, generally for internal company use only, reflecting a more limited data set and assessment maturity.

[k] Reserves reporting of discovered accumulations is regulated by tight controls for informed investment decisions to quantify differing degrees of uncertainty in recoverable volumes.

Produced oil or gas that has been brought to surface (production) and sold on international markets or refined in-country are no longer reserves and are removed from the booking and company balance sheets.

[n] The uncertainty in the estimates for recoverable oil & gas volumes is expressed in a probability distribution and is sub-classified based on project maturity and/or economic status (1C, 2C, 3C, ibid) and in addition are assigned a risk, or chance, to exist in reality (POS or COS).

[g] Prospective resources, being undiscovered, have the widest range in volume uncertainties and carry the highest risk or chance to be present in reality (POS or COS).

[18] The ratio between in place and recoverable volumes is known as the recovery factor (RF), which is determined by a combination of subsurface geology and the technology applied to extraction.

There are three main categories of technique, which are used through resource maturation to differing degrees: analog (substitution), volumetric (static) and performance-based (dynamic), which are combined to help fill gaps in knowledge or data.

While new technologies have increased the accuracy of these estimation techniques, significant uncertainties still remain, which are expressed as a range of potential recoverable oil & gas quantities using probabilistic methods.

[22] Analogs are applied to prospective resources in areas where there are little, or sometimes no, existing data available to inform analysts about the likely potential of an opportunity or play segment.

[1] Analog-only techniques are called yet-to-find (YTF), and involve identifying areas containing producing assets that are geologically similar to those being estimated and substituting data to match what is known about a segment.

Probabilistic volumes are calculations when uncertainty distributions are applied as input to all or some of the terms of the equation (see also Copula (probability theory)), which preserve dependencies between parameters.

It requires some production to occur (typically 5% to 10% of ultimate recovery), unless reliable pressure history can be used from a field with similar rock and fluid characteristics.

The term reserve growth refers to the typical increases (but narrowing range) of estimated ultimate recovery that occur as oil & gas fields are developed and produced.

[1] Oil or gas in unconventional reservoirs are much more tightly bound to rock matrices in excess of capillary forces and therefore require different approaches to both extraction and resource estimation.

Ultra low permeability reservoirs exhibit a half slope on a log-plot of flow-rates against time believed to be caused by drainage from matrix surfaces into adjoining fractures.

[31] Such reservoirs are commonly believed to be regionally pervasive that may be interrupted by regulatory or ownership boundaries with the potential for large oil & gas volumes, which are very hard to verify.

Extrapolations from a single control point, and thereby resource estimation, are dependent on nearby producing analogs with evidence of economic viability.

Flaring a flow test, the first outward indication of a new oil or gas discovery, which has the potential to qualify for reserves assessment
An oil well in Canada
An example of a Volume Uncertainty Distribution, with the P10, P50 and P90 volumes indicated (created using a probabilistic calculation method)
Schematic graph illustrating petroleum volumes and probabilities. Curves represent categories of oil in assessment. There is a 95% chance i.e. , probability, (P95 and often referred to in the industry as F95) of at least volume V1 of economically recoverable oil, and there is a 5% chance (P05 or F05) of at least volume V2 of economically recoverable oil. [ 15 ]
Example of a production decline curve for an individual well