Petroleum Reserves, Determination

Petroleum Reserves, Determination


Petroleum reserves are the recoverable portion of hydrocarbon accumulations that exist below Earth's surface in traps or reservoirs. The quantification of these reserves is essential to the world's effort to utilize hydrocarbons as a major energy source. The identification of petroleum reserves, both foreign and domestic, is an increasingly important scientific component of national economic and strategic security.

The process of quantifying reserves is governed by a host of scientific, political and economic considerations. Reserve determination is an interpretive process for which there is no finite answer until the end of a reservoir's producing life. Independent reserve estimates for the same asset base can vary significantly even though based on the same source data and with the application of prudent and customary technical methods. For general studies and large scale planning purposes statistical methods may be used to project reserves within an acceptable range of uncertainty, but specific projects beyond the earliest exploratory phase require at least a minimum of physical data. Uncertainty in reserve estimates is inversely proportional to the understanding of the producing characteristics of the accumulation and will remain a concern throughout the life of the project.

Uncertain reserve estimates for a reservoir or an entire project typically decrease over the life of a project as more factual information becomes known and actual production is observed.

Reserve estimates during the pre-drill exploratory phase are often based on known geologic factors from other areas thought to be sufficiently similar to the area under study applied to a reservoir description based on site specific interpretive data. In-place and recoverable reserve factors are applied to volumetric maps derived from seismic data and other geologic studies. The range of uncertainty at this time can be quite large. The actual existence of hydrocarbons has yet to be verified by actual well data and characterized as to their nature, quality, and economic viability. All studies at this point are speculative and highly dependent upon the creditability of the data available.

The first well drilled in the prospect enables project geologists and engineers to begin refining the assumptions used in the initial reservoir characterization efforts. Just how much this initial information improves the reserve estimate depends upon the degree and quality of data obtained. Each additional exploratory well adds more information and further refines the reserve estimates until it becomes possible to make a decision to go forward with project development or not based on an assessment of technical and economic risks. Ideally an actual flow test that includes a brief flow test of reservoir fluids and collection of fluid samples is conducted during this phase. However, this is not always done if confidence in other data more easily obtained is high and correlates well with the expected outcome, as flow testing can be quite expensive.

Each additional well, either as an expendable appraisal or a development well, further refines the data available and improves the interpretive understanding of project potential and further reduces but does not eliminate uncertainty in the reserve estimate. Until actual sustained production is established, the reserve estimate remains a volumetric determination and is highly dependent on the accuracy of the reservoir description. Nonetheless, the decision to make the significant capital investments required for project development is often based on a risked assessment of reserve potential with much yet unknown.

First production is a significant step toward improving the quality of reserve estimates. With continued geologic and engineering study and surveillance of actual reservoir performance the assumptions used to make previous reserve estimates are further refined with greater confidence. The range of uncertainty in the reserve estimate continues to narrow with actual performance.

Considerations that must be taken into account when estimating reserves tend to fall into the four categories of geology, fluid behavior, reservoir mechanics, and economic and political considerations.

Many of the geological factors considered in making the estimate of in-place reserves have to be refined and described in considerably greater detail if their effects upon hydrocarbon recovery are to be understood. These factors include but are not limited to structural geometry, size, shape, rock composition and compressibility, porosity, permeability, and compartmentalization.

The reservoir must be thought of in its three-dimensional configuration (e.g., whether it is in the shape of a box, sphere, dune, or an ancient river channel or a beach; whether it spreads over a massive area or it is intermittently scattered; whether is it flat, tilted, or undulating). Other considerations include analysis of whether the rock is clean sand, a mixture of sand and shale, limestone, or a number of other potential rock types that behave differently. A fundamental question involves whether the rock will compress as reservoir pressure depletes with fluid withdrawal. The degree of rock porosity—and the degree of minute rock particles called "fines" that exist in the pore space—are important considerations in determining whether the well will flow smoothly. Without effective permeability, the reservoir is of limited value. Once these other factors are known, the critical issue of compartmentalization remains (e.g. whether the reservoir is broken into sub-compartments by structural fractures or variations in permeability or whether fractures are sealing so as to prevent fluid flow across them). Obviously the more actual well data in an area, the better able one is to answer these questions. Until such data is available, advanced interpretations of seismic surveys and geologic models will be made and refined as well data is incorporated into the process.

The character of the reservoir fluid itself is a critical factor. Geologists conduct specific tests to determine the in-place gas or liquid phase and to what degree the phase is affected by temperature and pressure changes. A gas phase has low viscosity and high mobility, while liquids may have a viscosity ranging from that of water to that of solid asphalt. In calculating in-place reserves, the pore space saturation of other fluids is considered, most notably water but other potentially existing fluids such as carbon dioxide, nitrogen, hydrogen sulfide, elemental sulfur and others must be accounted for. The analysis of fluid and rock samples is critical.

Recovery is also dependent on which fluid actually wets the rock grain surface and to what extent resulting capillary pressures retain fluids within the rock matrix. These effects may restrict fluid flow through the porous rock media and govern how much of the original fluid saturation in-place can be recovered and how much will remain as residual saturation. Depending upon the lithology of the reservoir rock, residual gas saturation (i.e., the fraction of in-place gas that will remain in the reservoir) can range between 15 percent and 50 percent. For oil, residual saturation may range between 18 and 65 percent.

Reservoir mechanics are a major determining factor in hydrocarbon recovery and represent the energy that causes mobile fluids to flow through reservoir rock, also know as the drive mechanism. In a gravity drainage system, there is little pressure trapped within the bound fluid and the primary moving force is the pull of gravity on the density of the liquid. The resulting recovery is quite low, as may be demonstrated by fully wetting a sponge then lifting it out of the water with out squeezing it to see how much water runs out and how much is retained; then try this experiment with a more viscous fluid.

If reservoir fluids are under pressure, they may expand as pressure is released. This condition is an expansion drive and one in which the expanding fluid effectively flows from high pressure at the reservoir boundary to low pressure in the producing wellbore. Fluid recovery in an expansion drive is better than gravity drainage. The gas phase and recovery will tend to be a function of the real gas law where the relationship between changing pressure, temperature, and volume must be also adjusted for changing gas compressibility. Liquid recovery will be a function of fluid expansion. However, fluid recoveries are limited to their own ability to expand, thus an expansion or pressure depletion drive still leaves a considerable amount of hydrocarbon behind.

The highest yielding unassisted drive mechanism is a water drive system. In this case, the hydrocarbon bearing zone is in contact with a considerably larger body of water that can effectively push the hydrocarbon to the producing well (s) as the water itself expands as in a depletion drive. The strength of a water drive system is dependent on the size of the supply of water, or aquifer, and its relative energy potential or source. The larger the aquifer, the better the water drive. However the manner in which the water or "flood front" moves through the reservoir has great effect on its displacement of hydrocarbons. Irregularities in rock quality can cause channels to occur that may cause the moving water to have a low sweepefficiency and possibly bypass large quantities of in-place hydrocarbons.

And of course a reservoir may exist in a combination of several drive mechanisms and each may dominate performance at different times in the life of the reservoir. Typically, under primary depletion, gas recoveries can range from as low as 50 percent to close to 90 percent of the original in-place volume. Oil recoveries will range between 5 percent and 35 percent and in some cases a little better. Artificial means of lifting fluids or adding energy to a reservoir with pumps, gas injection, or water injection as secondary recovery projects can increase recoveries to some extent. In less frequent occurrences, tertiary recovery techniques may be applied through several forms of miscible flooding with a fluid that will reduce the residual oil saturation left behind or going as far as starting a fire flood within the reservoir. However the incremental recoveries to be gained from secondary and tertiary recovery can be costly to put in place and have their own inherent uncertainties that must be closely monitored.

Economic and political considerations will also impact recoverable reserves. As a field declines, it will ultimately reach an economic limit beyond which it is impractical to continue producing operations. The economic limit is impacted by declining well productivity, higher maintenance expense late in the life of a field, changing commodity prices, taxation and the cost of employing technology, and complying with changing rules and regulations. Very often the economic limit is one of the most uncertain factors affecting ultimate recovery.



Craft, B. C. Applied Petroleum Reservoir Engineering, 2nd ed. Englewood Cliffs, NJ: Prentice Hall, Inc., 1991.


DOE (United States Department of Energy)

User Contributions:

Comment about this article, ask questions, or add new information about this topic:

Petroleum Reserves, Determination forum