Classification of reserves and resources

Nobody has seen oil and gas underground as a whole. Their quantity is inferred from wells, seismic data and analogies (similar fields), and every estimate has an uncertainty. Besides, not everything that is in the ground will be produced: part will stay in the reservoir with any technology, part will not pay back its costs, and part has not been found yet. A classification sorts the total quantity by these features, so that different people understand the same number in the same way.

• Has the accumulation been discovered? It is taken as discovered when a well has proved the presence of moveable hydrocarbons (hydrocarbons that can flow): by an inflow during a test, by samples, and by log and core data. Everything else is undiscovered, and it is estimated from geological reasoning, together with the probability of success (Geological risk and chance of success).
• Can it be recovered? The recoverable part is what a defined development project will bring to the surface. The rest will stay in the reservoir (hydrocarbons in place and recoverable volumes).
• Is it profitable, and has it been decided? Quantities become commercial when there is a project that pays back and an intention to carry it out.
• How confidently has it been estimated? At any stage a quantity is a range, from a cautious to an optimistic estimate (Probabilistic volumetrics by Monte Carlo simulation).

PRMS (the Petroleum Resources Management System) was adopted in 2007 by the Society of Petroleum Engineers (SPE), the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE). The Society of Exploration Geophysicists (SEG) supported it. In 2018 the SPE approved an updated edition. This edition was also approved by the WPC, AAPG, SPEE, SEG, the European Association of Geoscientists and Engineers (EAGE) and the Society of Petrophysicists and Well Log Analysts (SPWLA). Companies all over the world use PRMS to manage their portfolios of projects. In many countries, the rules on what companies must publish about their reserves rely on it. It also serves as the oil and gas part of the United Nations Framework Classification for Resources (UNFC). The document has an official translation into Russian; where the two differ, the English text governs.

The main unit of PRMS is the project: one well, the development of an accumulation or of a group of accumulations, an infill drilling programme (extra wells drilled between existing ones), or gas injection. Recoverable quantities are estimated for a project, and the whole project is placed in one class. A company shows its own share under the terms of the contract (Licences and contracts for subsoil use). On one accumulation there can be several projects of different maturity at the same time, for example a developed part with reserves and an undrilled block with contingent resources.

Reserves

the quantities that are expected to be commercially recovered by development projects of known accumulations from a given date under defined conditions. They must be discovered, recoverable, commercial and remaining at the date of the estimate.

Contingent resources

the potentially recoverable quantities of known accumulations for which the project is not yet commercial because of one or more contingencies (conditions that are not yet met): there is no market, a technology is needed that is not yet ready, the accumulation is not studied enough, or there is no decision or approval.

Prospective resources

the quantities that could be recovered from accumulations not yet discovered, by future projects. We estimate both the volume if successful and the chances of discovery and development.

Unrecoverable

the part of the quantities in the ground that no project defined at the date will recover. Part of it may become recoverable with new technology or new prices.

Within a class, quantities are divided into categories by uncertainty. The cumulative estimates are the minimum, the best and the maximum (low, best, high): for reserves these are 1P, 2P and 3P, for contingent resources 1C, 2C and 3C, and for prospective resources 1U, 2U and 3U. The increments of reserves are called proved (P1), probable (P2) and possible (P3). 2P is proved plus probable, and 3P adds the possible.

For contingent resources to become reserves, a project must pass a check of commercial justification. All of the following are needed at the same time. The development plan is technically sound and realistic. Financing is in place or very likely to be secured. There is a justified schedule by which drilling will start within a reasonable time, usually not later than five years. The project economics are positive for the best estimate (a company may also check them for the low estimate). There is a market for the product and a way of disposing of the associated components. The infrastructure has been built or can be built. Permits and approvals have been received or are expected. And the company and its partners firmly intend to carry out the project.

Reserves are also divided by status. Developed reserves are produced with existing wells and facilities. They are either being produced already or waiting for small costs (shut-in intervals, which are temporarily closed, and layers behind the casing, the steel pipe that lines the well). Undeveloped reserves need large investments in new wells or facilities.

We can find a range of recoverable quantities in three ways, and we can combine them. Deterministic with increments: we first estimate the proved quantities, then separately how much the probable and possible add. Deterministic by scenarios: we build three consistent cases of the whole project, a low, a base and a high one. Probabilistic: we specify distributions of the input quantities and get a distribution of the result, from which we read P90, P50 and P10 (Probabilistic volumetrics by Monte Carlo simulation).

• The proved area consists of the parts outlined by drilling and limited by fluid contacts, and the neighbouring undrilled parts that, from the available data, continue the accumulation with reasonable certainty and are productive.
• Lowest known oil. If a well has not reached the contact, the proved quantities stop at the greatest depth at which wells have proved hydrocarbons (“oil down to”), unless convincing data, for example pressure gradients (Pressure gradients, fluid contacts and capillary equilibrium), show otherwise. Seismic alone is usually not enough for this.
• Probable are the parts next to the proved ones, where the data or their interpretation are less reliable, and the additional quantities that come from a higher recovery factor than the one taken for the proved.
• Possible are still further out and still less reliable. Possible reserves outside the 2P area are allowed only if the project to develop them is commercially and technically mature.

The estimates of different fields can be added in two ways: arithmetically by categories, or statistically by combining the distributions. The results differ noticeably: the sum of the P90 values of separate fields is smaller than the P90 of their sum (adding up estimates). For reporting, PRMS recommends adding arithmetically above the level of a field, area or project, and stating that the sum of 1P may be too cautious and the sum of 3P too optimistic.

Kazakhstan has its own national system of categories. It is based on the Instruction on the classification of deposit reserves and forecast resources of minerals, approved by Order No. 208 of the Minister of Industry and Construction of 28 April 2026. With it, Order No. 207 approved the methodologies for estimating reserves. For oil and gas, the reserve categories A, B, C1 and C2 and the resource categories C3, D0, D1 and D2 were kept. The instruction contains no references to international systems.

The categories answer the question “how well has this part of the accumulation been studied”. So their boundaries are drawn from wells. At the exploration (appraisal) stage, we draw the C1 boundary around a well with an inflow, at a distance equal to twice the drainage radius of its zone (the distance from the well from which oil flows to it). We find that radius by testing. At the production stage, under the approved project, we draw the boundary at twice the distance between production wells. The rest of the accumulation inside the outline is C2. The contact sets the outline of the accumulation. Until wells reach it, the depth of the contact is taken from the patterns of neighbouring accumulations or from the fill factor of neighbouring traps (how much of the height of a trap is filled with hydrocarbons). As drilling proceeds, reserves are moved step by step from C2 to C1 and then to B.

The second division is economic. Geological reserves are divided into profitable (recoverable) and unprofitable (off-balance) ones. The recovery of profitable reserves pays off with modern, proven technologies, while meeting the requirements of subsoil and environmental protection. Unprofitable reserves are not worth recovering with today's technology. The recoverable part is set by the recovery factors of oil, gas and condensate (light liquid that comes out of natural gas): the share of reserves that is recovered under the optimal regime up to the limit of profitability (recovery factor). For accumulations at the exploration stage, the factors are taken by analogy or by simplified statistical methods. For developed accumulations, they are taken from the technical and economic justification of the recovery factor for the recommended development option. The recovery factor for C2 is taken, by analogy, as not more than 75% of the factor for C1.

• By complexity of structure, fields are divided into three groups: I, simple structure; II, complex structure (non-uniform thicknesses and properties, or faults); III, very complex structure.
• By degree of development: developed, prepared for development, under exploration, and mothballed (temporarily shut down). The state balance of minerals (the official register of reserves) accounts for the reserves in each separately.
• A field is handed over for commercial development when the reserves and the technical and economic justification of the recovery factors have passed the state expert review, the effect of development on the environment has been assessed, and the degree of study by the commercial categories A+B+C1 is more than 50%.

The state categories are not the private opinion of the subsoil user. Reserves and resources of hydrocarbons are subject to state expert review, and, on its results, to state registration in the balance of minerals. The way from the first inflow to reserves on the register is set by the Subsoil Code and the instruction.

A negative conclusion is issued if the estimate does not conform to the normative and technical documents, if the information on the quantity and quality of the reserves is unreliable, or if the data presented do not allow an objective assessment. The conclusion states what must be improved. Until 1 January 2030, under the transitional provisions of the Code, the state reserves commission carries out the review. The authorised body for the study of subsoil (now the Ministry of Industry and Construction) approves its regulation. After that date the Code gives it to the central commission for hydrocarbon reserves, whose regulation is approved by the authorised body for hydrocarbons. Reviews of development projects are carried out by a different commission, the one for exploration and development (State regulation of field development).

In Kazakhstan, the categories and the expert review of reserves are built into the subsoil use contract. Here is where exactly (the Subsoil Code as worded in October 2026).

• Trial production is allowed only under a project that was accepted for review after a positive conclusion on the operational estimate of reserves (Article 139).
• The production area. Its boundaries follow the outlines of the field from the reserves estimate report with a positive review conclusion (Article 110). The preparatory period is fixed only with such a report, and the production period with that report and the development project (Articles 118 and 119).
• The length of production. Up to 25 years, and for large fields (geological reserves of more than 100 million t of oil or more than 50 billion m³ of gas) up to 45 years (Articles 14 and 119).
• An obligation for large discoveries. If the initial geological reserves that passed the review are more than 100 million t of oil or 50 billion m³ of gas, the contract must include one of these obligations: to create a processing plant, to modernise or rebuild an existing production or processing plant, to supply raw material for processing in Kazakhstan, or to carry out another investment or social project (Article 119).
• A strategic subsoil area has geological reserves of more than 50 million t of oil or 15 billion m³ of gas, confirmed by a report with a positive review conclusion (any area in the Kazakhstani sector of the Caspian Sea is also strategic). The state priority right (the state's right to buy ahead of others) applies to the transfer of rights in it (Article 43; more details).
• The signature bonus. For an area with approved reserves, the starting amount is calculated from the value of the reserves by category (the formula below). Without approved reserves the bonus is fixed in monthly calculation indices (MCI). The rates and the order of payment are on the MunaiHub page “Subsoil-user taxes” in the “Legal library” section.

For a company whose shares or bonds are traded on an exchange, another estimate matters more: it discloses reserves to investors and lenders by international rules, by PRMS or by the rules of the exchange regulator of its country. So one field often has two official estimates: by the state classification, for the state and the contract, and by PRMS, for the capital market. We cannot compare them directly: they answer different questions.

Let us follow how the classification of one discovery, the assumed structure “T-1”, changes from a prospect to a decision to develop. The structure is a dome with a closure of 80 m (the height from the crest to the spill point). The crest is at a depth of 2400 m, and the spill point (the lowest level to which the trap can hold oil) is at 2480 m. The closing contour is an ellipse with semi-axes of 3 and 2 km. This is the surface of the top of the layer; the layer, 30 m thick, follows its shape. All the data in this example are assumed for illustration.

It is tempting to make a table “C1 = 1P, C2 = 2P − 1P”, but the example above shows why there is none. The systems differ at the very base, and the same accumulation is described in them by numbers that need not coincide.

What the systems have in common is the boundary “discovered / undiscovered”: C3 resources and the D categories, like the prospective resources of PRMS, belong to accumulations not yet discovered, and C1 and C2 to discovered ones. But PRMS divides the discovered quantities into reserves and contingent resources by project maturity, and the state system divides them into C1 and C2 by degree of study. So we compare not the categories but the input data: the maps, the contacts, the parameters and the recovery factors. The United Nations Framework Classification (UNFC), in which PRMS serves as the specification for oil and gas, is meant as a bridge between national systems.