Home → Upstream

Understanding Reserves

• Who Defines Reserves?
• SEC Reserves Definitions
• Basic Definition of Proved Reserves
• Developed Versus Undeveloped Reserves
• Reserves Estimation Methods
• Reserves Reporting for the Mineral/Royalty Interest Owner

Who Defines Reserves?

One of the factors complicating the definition of reserves is that, over the years, several industry and governmental bodies have established their own definitions. These include the Society of Petroleum Engineers (SPE), the Society of Petroleum Evaluation Engineers (SPEE), the American Association of Petroleum Geologists (AAPG), the World Petroleum Congress (WPC), the United States Securities and Exchange Commission (SEC), the Internal Revenue Service of the United States Treasury (IRS), and governmental agencies in other countries. Fortunately, many of these groups have attempted to standardize their reserves definitions. Most notably, the industry groups mentioned above (SPE/SPEE/AAPG/WPC) have made continual progress toward standardization, and they recently jointly adopted and issued a document entitled "Petroleum Reserves and Resources: Classification, Definitions and Guidelines."

Back to top

SEC Reserves Definitions

The SEC regulates the reporting of "proved" reserves for publicly traded companies in the United States. Many of the reserves definitions proposed in the latest draft by the SPE/SPEE/AAPG/WPC are similar to the SEC reserves definitions, at least with respect to proved reserves. Also, because public companies must report reserves in accordance with SEC rules, other parties who rely on private reserves reports often specify that those reports also adhere to SEC rules. These include banks and other lenders, as well as private equity investors. The SEC proved reserves definitions were published in 1978.

Back to top

Basic Definition of Proved Reserves

The SEC defines "proved" reserves as "the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions..."

Given this definition, there are a few observations that one could immediately make about proved reserves estimation. First, since proved reserves are future quantities to be produced, there is some uncertainty about what those quantities will be. To deal with this uncertainty, the SEC states that the estimates must be made with "reasonable certainty," which they have defined as "conservative," in the sense that any future change to the estimate is much more likely to be positive rather than negative.

Secondly, engineering and geological data are needed to make the estimates. Generally speaking, the knowledge offered by greater amounts of engineering and geological data will improve the quality of the reserves estimate.

Lastly, proved reserves must occur in known reservoirs — that is, reservoirs that have already been discovered by drilling.

Back to top

Developed Versus Undeveloped Reserves

Proved reserves are categorized as either "developed" or "undeveloped." The primary difference between these categories is whether or not the majority of the investment required to produce and sell the oil and gas has been made. In most cases, this means, "Have the wells been drilled?" If the wells have been drilled, and all (or almost all) of the infrastructure necessary to produce and sell the oil and gas has been installed, then the reserves may be considered developed.

Many companies carry reserves in their reserves report that are undeveloped. These are quantities that could be recovered from their properties, but would require significant additional investment to produce them. A very common example of undeveloped reserves would be those which underlie undrilled portions of their property that are adjacent to current producers and are, based on engineering and geological evaluation, reasonably likely to produce hydrocarbons from known reservoirs.

Back to top

Reserves Estimation Methods

There are at least four broad methods of estimating the reserves of oil and gas accumulations.

• Volumetric Method
• Material Balance Method
• Performance Methods
• Reservoir Simulation Method

Each of these methods requires a set of engineering and geological data (some more than others), and each is subject to certain limitations. All of them rely on many assumptions, so they do not provide precise estimates.

Volumetric Method

The basic idea here is that if the approximate size of the underground accumulation (the area it covers and its thickness) is known, as are the nature of the rocks within which the oil and gas are present, and some physical properties of the oil and gas itself, then engineering formulas can be used to estimate the amount of oil and gas originally "in place." By estimating the fraction of the in-place volume that will ultimately be recovered, the "estimated ultimate recovery" (EUR) may be determined. The reserves equal the EUR less any production that has already occurred.

This method is a good one and is often used early in the life of a field. It does require a lot of data for the inputs, however, and if that data is not available, then assumptions must be made. As more wells are drilled and more engineering and geological data is gathered, these estimates generally become more accurate.

Material Balance Method

This method relies on the assumption that the reservoir is a closed system, and a relationship exists between the pressure within the reservoir and the amount of hydrocarbons removed from it. If the system is indeed closed (for example, there is not an aquifer beneath the hydrocarbons), and the engineer has accurate knowledge of the historical production and reservoir pressures, this data can be used to forecast the total recovery from the reservoir until it reaches its abandonment pressure. It is a reliable method if the underlying assumptions are met and if sufficient data, particularly reservoir pressures, are available.

Performance Methods

Performance methods rely on preparing graphs of a historical well (or reservoir) performance measure (such as production rate, cumulative production, pressure, water cut, gas/oil ratio, etc.) versus time or another performance measure. The resulting curve is extrapolated into the future to estimate the potential performance of the well.

One of the widely used performance methods is "decline curve analysis." This method involves graphing the logarithm of the production rate versus time, and then extrapolating the curve into the future to predict the production rate. This method often yields accurate estimates of future performance and offers the additional benefit of requiring relatively little data.

Performance methods can only be applied to wells that are actually producing, so this limits their application to estimates of "proved, developed, producing" (PDP) reserves. Broadly speaking, performance methods do not directly allow the engineer to book undeveloped reserves, but, by analogy, they can be the basis for a preliminary estimate of how offsetting undeveloped wells might perform.

Reservoir Simulation Method

Reservoir simulation is a process of describing the geological, mechanical and fluid properties of the reservoir in a complex mathematical model, fine-tuning these inputs to match the performance of the reservoir to date (history matching), and then letting the model run to predict future performance. It is a very useful tool and is widely used to make critical investment decisions, but it has limited utility in proved reserves estimation.

First, the fact that a history match is obtained does not prove that the future predictions are correct or even reasonable. Secondly, it is costly, time-consuming and requires a tremendous amount of engineering and geological data, much of which is not routinely available.

Back to top

Reserves Reporting for the Mineral/Royalty Interest Owner

Reporting proved reserves for mineral and royalty interests is somewhat different from reporting reserves for operating working interests. The differences fall into two broad areas: less engineering data and an inability to directly control development operations.

Engineering Data

Due to the terms of most leases, the mineral/royalty interest owner is almost never entitled to all of the data that the operator gathers in the course of drilling and operating the wells. Here are some examples of important data sources that the mineral/royalty owner generally does not have access to:

• Seismic data
• Well logs
• Fluid analyses
• Core analyses
• Geologic maps
• Reservoir pressure data

Because of this, the mineral/royalty interest owner is generally not able to use the volumetric or reservoir simulation methods for estimating reserves. In general, this lack of engineering data means that the mineral/royalty owner can often only rely on performance methods for reserves estimates, and, by definition, these methods can only be used to estimate PDP reserves.

Control of Development Operations

This issue relates mostly to the booking of undeveloped reserves. Even if the mineral/royalty interest owner has sufficient engineering and geological data to support an estimate of undeveloped reserves, his non-cost-bearing interest generally makes it impossible for him to control whether and when the necessary capital investments will be made to develop these reserves. The SEC requires that undeveloped reserves have a reasonable plan for development, and that the party who books the reserves can influence the execution of the plan. However, the mineral/royalty interest owner does not generally exercise control over the development plan, so he rarely can book undeveloped reserves. This is another reason why almost all of the reserves associated with EROC's mineral and royalty interests will be classified as PDP.

Back to top