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ISBN Get permission for reuse. The SPE and the WPC continue to work together to improve these definitions in light of several unresolved ambiguities. For deterministic estimates, quantities for each of the three reserves categories of proved, probable, and possible are estimated, and the evaluator is cautioned not to add these quantities together because of the handbooj degrees of uncertainty associated with each.

Conversely, the probabilistic approach requires the addition of “proved plus probable” or “proved plus probable plus possible” categories to comply with the stated numerical levels of uncertainty. Further, definitions place handbiok specified limitations on the “lowest known occurrence of hydrocarbons,” average prices, and conformance to regulatory well spacing where applicablethus reducing the variables that are subject to classic probabilistic reserves assessment.

Cronquist [3] has provided comments regarding interpretation of some of the terms used in these definitions. New definitions were approved in Certain SABs published after Regulation S X [10] concern the application of financial accounting and disclosure rules for oil and gas producing activities.

They represent interpretations and practices followed by the U.

SEC Regulation S K [13] prohibits the disclosure of estimated quantities of probable and possible reserves of oil and gas and any estimated value thereof in any documents publicly filed with the Commission. In a 21 February website release, [14] the U. SEC addressed several topics relative to the reporting of proved reserves. No changes were made to the definitions, but the U. SEC engineering staff modified its application and interpretation of those definitions in light of the widespread technological advances in over the previous 20 years.

The most significant of these application changes are discussed below. Regulatory authorities worldwide have been encouraged to use these definitions as much they reasonably can for their specific purposes. SEC definitions were approvedvirtually all regulated companies were in the U. Also, virtually all natural gas then was sold through long-term contracts with a defined pricing structure. Oil prices were less volatile then, compared with price swings seen over the past 10 to 15 years.

Privatization of numerous national or state-owned oil and gas companies, with the sale of their securities within the U.

SEC definitions both use “reasonable certainty” to describe the controlling condition for proved reserves, but neither offers quantification of the term. Most engineers now accept that reasonable certainty indicates relatively high confidence. Proved reserves estimated using deterministic methods seldom, if ever, will meet a P90 requirement. Most volumetric estimates use average porosity, average water saturation, and recovery efficiencies REs that are consistent with expected reservoir drive mechanisms and operating conditions.

For another example, when using a conservative RE because of an unknown drive mechanism and a lowest known limit of oil LKO or gas LKGthe equivalent confidence level may be between P50 and P For performance estimates using trend analysis, the engineer typically will extrapolate a “best fit” from the historical information, which essentially reflects a P50 estimate.

SEC definitions refer to as known reservoirs. In the hndbook, a known accumulation is an underground collection of moveable petroleum—one or more reservoirs confirmed through the drilling and gathering of reservoir data from one or more wells. A known accumulation must be considered commercial before reserves of any classification may be cpal. SEC definitions [10] specify that proved reserves are to be reported consistent with “existing economic and operating conditions; i. For products sold in a spot market, the pricing available on the report date should be used.


Operating costs typically are costs averaged over the preceding 12 months, unless a change material to the estimate has occurred coa the preceding 6 months. SEC continues to enforce the definitions regarding undeveloped well locations, requiring that the proved classification be given only to those locations beyond one offset from a productive well where “it can be demonstrated with certainty that there is continuity of production” [emphasis added] from the existing productive formation.

A subsequent clarification released by the U. SEC in [14] stated that “there is no mitigating modifier for the word certainty. First, the term “offset” refers to regulatory-controlled well spacing in North America and to few areas, if any, elsewhere. Second, and more importantly, the term “certainty” is used here by the U. SEC to describe undeveloped reserves, whereas the controlling term in the first sentence of the U.

SEC definitions is “reasonable certainty. Requirement for Flow Testing. Both definitions also permit exceptions in certain cases. SEC may grant an exception for a definitive flow test for a particular reservoir if core and log data indicate commercial productivity and the reservoir is analogous to one or more flow-tested or producing reservoir s in the same field. There is increasing interest by evaluators using both the U. Gulf of Mexico, where physical well testing is impractical because of costs and environmental concerns.

Many of these discoveries are not close to other fields, but may be characterized by thick sections of highly permeable sandstones saturated with high-API-gravity, low-viscosity crudes and exhibiting reservoir pressures in excess of 8, psia.

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In such scenarios, flow calculations can confirm production rates that are considerably higher than the minimum commercial rates, and are adequate for producers to make commercial decisions about facility sizing and project sanctioning. The evaluator determines on a case-specific basis whether such indirect data are adequate to confirm commercial flow rates without a physical flow test in consideration of the applicable definitions.

Areal Extent of a Reservoir. In the absence of such contacts, limits are imposed by the LKO or LKG, which typically are defined as the subsea depth of the base of the permeable reservoir, as recorded on well logs. Only in recent years has the U. SEC begun to consider indirect measurements or calculations of controlling ccoal. In their acceptance of a limiting contact below the base of the lowest logged interval, the U. SEC engineering staff may further consider the gwd of the quantity of reserves added through the use of pressure-gradient data.

They provide no definition of materiality. Also, agreement between two or more indirect measurements would be required as the basis for establishing proved reserves. SEC traditionally has required that the proved designation be limited to reservoirs where enhanced-recovery improved-recovery methods have been demonstrated through a successful pilot project or an installed program “in the reservoir. The subject reservoir should have reservoir and fluid parameters that are equal to or more favorable than those of the analog reservoir s.

SEC definitions contain many other wording differences regarding proved reserves, but those cited above are of major importance. For questions of interpretation or application, however, the U. SEC typically will respond to inquiries by interested parties. Other petroleum-producing countries and regulatory authorities have promulgated petroleum reserves definitions that are recognized and based on years of development and sound engineering judgment, but none—however important in their sphere of influence—with such far-reaching consequences as the U.

See Cronquist [3] for a summary of many of these other definitions. Each of these is discussed briefly in the next two sections.

Thereafter—except for another section on probabilistic procedures near the end—the chapter will focus on deterministic procedures because they still are more widely used. Both procedures need the same basic data and equations. Probabilistic procedures recognize that uncertainties in input data and equations to calculate reserves may be significant.


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Accordingly, each input parameter uses a reasonable range of values, from which a set of reserves calculations is made. Methods to estimate reserves may be categorized as either static or dynamic. Gsc methods typically are used before production is initiated in a subject reservoir, and include analogy methods and volumetric methods. Computer simulation that is used before production initiation is considered a static method.

Dynamic methods might be used handdbook sustained production has been initiated, and include production trend analysis, material-balance calculations, and computer simulation. A specific reserves estimate might involve one or more such methods.

What method or methods are used depends on several factors, including production history of the area, if any; stage of development on the date of the estimate; geologic complexity; quality and quantity of data; maturity of production for the subject reservoir; and the purpose of the estimate. Each estimate should be corroborated using an alternate, preferably independent, method.

Information presented in Tables Two types of statistical analogy methods are discussed here: Additional comments are provided in the Recovery Efficiency section below. In some producing areas, ultimate recovery of oil or gas from individual wells may be controlled by geologic trends such as depositional environment, intensity of fracturing, or degree of diagenesis. In such cases, an isoultimate recovery map can be made by posting and contouring estimated ultimate recovery from individual wells in the area of interest.

Such a map can be used to estimate reserves for undrilled tracts, but one should use this technique cautiously! Nongeologic factors might control ultimate recovery of oil or gas. Different completion and stimulation procedures may yield different ultimate recoveries from individual wells. For example, for wells in several areas of the U. Wells in the area of interest may be capable of draining more than a “spacing unit. One should investigate these possibilities before using an isoultimate recovery map to estimate reserves for undrilled tracts.

An alternative to isoultimate recovery maps is the use of “bubble maps,” in which the size of the circle drawn around a wellbore is proportional to the parameter or measurement being compared.

If there are significant differences in these factors from one property to the next, be careful in making comparisons or statistical analyses of wells between such properties.

Most statistical data handboook RE in the U. These are not typical conditions in other areas of the world, especially offshore areas; thus, one should exercise caution when using REs determined from U. Although volumetric methods are the most widely used methods for estimating reserves, results from their use might be subject to considerable uncertainty, depending on the geologic setting and the amount and quality of geologic and engineering data.

Thus, it is recommended that an evaluator compare reserves estimated by volumetric methods against well and reservoir performance at the earliest practical stage of production and make adjustments as warranted. Volumetric methods for estimating reserves involve three steps:. For oil reservoirs, initial reserves of oil and solution gas can be calculated using Eq.

Remember, however, that all calculations of reserves must be considered estimates coall, and are accurate to no more than two significant figures. For analyses where A o h no is determined from planimetry of isopach maps: Initial reserves of solution gas can be calculated by: Gas initially in place GIP may, alternatively, be calculated with an equation analogous to Eq.

Most volumetric methods begin with determining the bulk reservoir volume that contains hydrocarbons. This usually involves preparing structure maps of the top and base of the reservoir and an isopach map of the reservoir.