Oil and gas reserves and resource quantification

• 1. Introduction

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  Oil and gas reserves and resource quantification is the practice of estimating how much hydrocarbon lies in the Earth's subsurface. The second, harder question it answers is how much of that hydrocarbon can realistically be brought to the surface. Reserves are the primary asset on any oil and gas company's balance sheet. The industry calls the process of adding reserve estimates to that balance sheet booking. That raises an immediate problem: the rock formations holding those hydrocarbons cannot be examined directly. They can only be inferred from seismic surveys, drilling results, and pressure readings. How does the industry translate that fundamental uncertainty into numbers firm enough for regulators and investors? And why do field estimates so often require upward revision as more data accumulates?

• 2. Resources Versus Reserves

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  Five professional bodies collaborated to produce the 2018 Petroleum Resources Management System, known across the industry as PRMS. The core contributors were the Society of Petroleum Engineers, the World Petroleum Council, and the American Association of Petroleum Geologists. Two additional bodies, the Society of Petroleum Evaluation Engineers and the Society of Economic Geologists, also joined the effort. Their shared goal was a single, consistent framework for estimating and classifying oil and gas quantities worldwide.

  PRMS draws a firm boundary between two terms that are often used interchangeably outside the industry. Resources cover all estimated hydrocarbons in place, whether or not they can ever be economically extracted. Reserves are narrower: the volumes expected to be commercially recoverable under existing economic, technological, and regulatory conditions.

  Classification within the PRMS also reflects how mature the underlying data is. A formation identified early in exploration carries far more uncertainty than one drilled and tested over many years. Prospective resources, being undiscovered, hold the widest range of uncertainty and the highest chance of not existing at all. Contingent resources are discovered but not yet suitable for commercial development. Reserves represent the most advanced stage in that spectrum.

  Resources are promoted to reserves only when two conditions are satisfied. Appraisal drilling must prove a sufficient commercial accumulation, and authorized, funded development plans must be in place. The recommended window for production to begin after that authorization is five years.

• 3. Three Grades of Certainty

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  P90 is the industry shorthand for proven reserves: a 90% statistical probability of producing at or above the stated volume. The industry also calls this category 1P. Within proven reserves, two further grades apply. Proven developed reserves, or PD, can be extracted using existing wells and infrastructure with minimal new investment. Proven undeveloped reserves, or PUD, require new wells or additional capital before the hydrocarbons reach the surface.

  Probable reserves sit at the next tier, designated 2P or P50. A 50% probability that actual recovered volumes will meet or exceed the stated estimate defines this classification. Varying geological interpretations are a common reason for placing volumes in the probable column rather than proven. Uncertainties about how hydrocarbons flow from adjacent areas into a production well are another.

  Possible reserves carry a 10% probability of meeting or exceeding their stated volume. The designation is 3P, or P10. Volumes projected from recovery methods not yet applied to a given field also fall into this category.

  Before January 2010, the U.S. Securities and Exchange Commission required oil companies to report only 1P proven reserves to investors. Since then, companies have been permitted to optionally disclose 2P and 3P figures, with discretionary verification by qualified third-party consultants. Many companies keep those broader figures for internal planning only. Companies listed on U.S. stock exchanges may be called on to verify their reserve claims. Many governments and national oil companies do not disclose their verifying data publicly.

• 4. Contingent and Prospective

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  Three sub-categories, labeled 1C, 2C, and 3C, organize contingent resources by project maturity and economic status. Contingent resources are discovered accumulations not yet considered mature enough for commercial development. Their commercial path is blocked by one or more conditions that have not yet been satisfied. Each category also carries an assigned probability of the accumulation actually existing in reality, referred to as POS or COS.

  Prospective resources carry the highest uncertainty of any class in the PRMS. Because they are undiscovered, their volume ranges are wider than those of any other resource class. Three sub-categories, 1U, 2U, and 3U, reflect that spread. Companies are generally not required to report prospective resources publicly. Some choose to do so voluntarily, because externally published estimates can raise investor perceptions of asset value and influence a company's share price.

  Both contingent and prospective estimates are typically kept for internal use. They reflect a more limited data set than reserves and are not subject to the same rigorous external verification requirements. A single resource estimate can represent an individual prospect or an aggregate spanning an entire geological basin, depending on the scope of the assessment.

• 5. Methods of Estimation

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  Analog methods, also called yet-to-find or YTF, identify geologically similar producing assets elsewhere and substitute their data for unknowns in the target area. YTF is most useful in frontier regions where no existing production provides a local reference point. The method can be scaled from a single reservoir to a global basin depending on the analyst's purpose.

  The volumetric equation for a conventional reservoir multiplies gross rock volume by net-to-gross ratio, porosity, fluid saturation, and a recovery factor. That figure is then divided by a formation volume factor to yield a recoverable volume estimate. Deterministic calculations use a single value for each input. Probabilistic calculations apply uncertainty distributions to some or all terms. These geostatistical approaches are most commonly applied to accumulations not yet tested by drilling.

  Reservoir simulation uses computer models to predict how oil, water, and gas move through porous rock. Daily production volumes can be matched against simulation forecasts to measure a model's accuracy. Unlike analog or volumetric approaches, confidence in simulation results grows with every additional dataset added. The longer a reservoir has been flowing, the more reliable the prediction of what remains.

  The materials balance method links volumes of oil, water, and gas already produced from a reservoir to observed changes in reservoir pressure. From that relationship, it calculates the remaining hydrocarbons. The method requires an accurate pressure history and extensive pressure-volume-temperature analysis. Typically, between 5% and 10% of a field's ultimate recovery must have occurred before the method can be applied.

  The decline curve method fits a mathematical curve to known production data and extrapolates it forward. The three standard forms are exponential, hyperbolic, and harmonic curves. The method requires a sufficient production history to establish a statistically significant trend. It also assumes production decline follows a reasonably smooth curve.

  Geoscientists, subsurface engineers, surface engineers, and economists typically work in integrated teams to produce a final volume estimate. New technologies have increased the accuracy of estimation, but significant uncertainties still remain, expressed as a range of potential recoverable quantities.

• 6. Reserves Growth

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  Reserve growth refers to the consistent pattern by which a field's estimated ultimate recoverable volume increases over time. Initial reserve estimates for newly discovered fields are almost always too low. As years of drilling, production, and pressure data accumulate, the picture sharpens. Successive estimates tend to rise, and as they grow larger, their range of uncertainty narrows.

  The International Energy Agency stated in 2021 that countries should no longer expand exploration or invest in projects to increase reserves. The IEA's stated rationale was meeting the climate goals set by the Paris Agreement. That position sits in direct tension with the commercial logic that has driven petroleum quantification for more than a century.

  Many oil-producing nations do not publish their reservoir engineering field data. They provide unaudited reserve totals instead. Some national government figures are suspected of being manipulated for political reasons. The absence of transparent verification makes it difficult to assess global reserve totals with the same confidence applied to individual company filings.

  Attempts to standardize national or basin-level resource reporting exist but lack the binding requirements that govern publicly listed companies.

• 7. The Unconventional Challenge

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  Coalbed methane, shale gas, tight oil, natural bitumen, oil shale, gas hydrates, and basin-centered gas all qualify as unconventional accumulations under the PRMS. Conventional oil and gas float above water within porous rock, held in place by the balance between buoyancy and capillary forces. Unconventional hydrocarbons are bound directly to the rock matrix by forces that exceed capillary pressure. Standard extraction techniques do not work in the same way, and commercial viability depends entirely on the technology applied to each specific reservoir.

  Ultra-low permeability unconventional reservoirs display a distinctive signature on a log-plot of flow rates against time. The pattern is a half slope on the curve, believed to result from drainage through matrix surfaces into adjoining fractures. Such reservoirs are often regionally extensive and may cross regulatory or ownership boundaries. Their potential volumes can be large, but their flow characteristics are not unique enough to confirm economic viability from geological data alone.

  Pilot projects are often required before any reserves from these formations can be formally declared. Without nearby producing analogs demonstrating economic viability, all remaining estimates stay in the analog-only YTF category. The industry treats those estimates as speculative. When pilot data does arrive, it becomes the evidence that moves an accumulation from speculative to a formally declared reserve.