I used to give a talk on reserve determination methodology to the "non-technical" staff at a previous employer. Below is a summary of that talk.
First, let's make sure we are all on the same page. Oil and gas is made up of hydrocarbon molecules of differing size. The size of the molecule is determined by the length of the carbon chain. The greater the length of the carbon chain the greater the size, weight and energy contained within the molecule. Methane (CH4), for example, is the smallest of the hydrocarbons with only one carbon atom. Methane is the lightest of the hydrocarbons and the main component of natural gas. Octane is another molecule that most of us have heard of and it has a carbon chain consisting of 8 carbon atoms. Octane is heavier than methane, contains more energy and is typically a liquid.
Petroleum in its natural state, that is when it's in its underground reservoir, usually consists of a complex mixture of hydrocarbon molecules. The composition of this mixture combined with the reservoir's temperature and pressure determine whether the petroleum will be in a liquid or gas phase in the reservoir (it is possible to have a solid in some special circumstances).
A petroleum reservoir is not a pool of oil floating in an underground cave. The reservoir consists of "solid" rock; well nearly solid. A reservoir rock has porosity (small holes within the rock that are usually not visible with the naked eye) and the hydrocarbons are contained within these pores in the rock. There are three substances found in reservoirs (not including the rock itself): Oil (liquid hydrocarbons), gas (gaseous hydrocarbons), and water. Hydrocarbons are lighter than water, so they tend to "float" and rise to the top of the reservoir. Gas is lighter than oil, so it wants to be on the top of the hydrocarbon mixture.
For a petroleum reservoir to exist it must have a means of trapping the hydrocarbons from floating away and forcing them to stay within the confines of the reservoir. Since hydrocarbons were generated millions of years ago, these traps that make up today's reservoirs have to be pretty good barriers to fluid migration.
Okay, so now that we are on the same page we can discuss how we can determine the size of a hydrocarbon accumulation contained within a reservoir. There are basically three different methodologies commonly used to determine the volume of oil and gas in reservoirs. These methodologies are used both independently and in combination. The selection of the appropriate method is determined by the characteristics of the specific reservoir, the judgment and experience of the evaluator, and the data available.
The first and most common methodology is the use of decline curves. Decline curves are used when a reservoir has been on production for some time and has demonstrated an observable trend (decline) in production rates. The technique is to construct a graph of production rate versus time on a semi-log scale (where production rate is on the log scale and time is on the normal scale) and then forecast the observed trend (decline) forward in time.
The art is in the forecasting of the decline. Some reservoirs exhibit a straight line (exponential decline) while others follow a curve with a lessening slope over time (hyperbolic or harmonic decline). Obviously the selection of the appropriate decline shape makes a big difference in the production forecast and thus the reservoir's reserves. The basic assumption in using a decline curve to forecast reserves is that the historical conditions that existed when the decline was observed will continue throughout the forecast.
Decline curves are the most commonly used method for determining PDP reserves because they can be constructed and forecast quickly, but this also occasionally results in their inappropriate use. Care must be taken to determine when it is appropriate to use a decline curve and when an additional or alternative method is required.
The second most common method of calculating reserves is to volumetrically determine the size
of the reservoir. This method is called "volumetrics" and requires some knowledge of the shape and size of the reservoir including its areal extent, thickness, porosity (percent of rock that is pore space) and relative saturations of oil, gas and water. This may sound easier than it actually is. Usually an experienced geoscientist is required to construct structure and "net pay" (the portion of the rock that contains hydrocarbons) maps of the reservoir and this in itself is subject to interpretation.
Given this geological information, and using basic geometry, the volume of the reservoir and its hydrocarbons can be calculated. This methodology results in the volume of hydrocarbons in place (OIP and GIP), but a separate determination must be made about how much of the hydrocarbons can be recovered (recovery efficiency).
Often volumetrics are used to determine the reserves associated with development or exploration projects (PDNP, PUD, Probable and Possible). This is because there usually hasn't been any production from the reservoir (the well hasn't been drilled yet) so the other methodologies, which rely on historical production data, can not be used. This gives rise to the common perception that volumetrics are less accurate than the other methodologies. This perception is not necessarily true, it's the project itself that has a greater degree of uncertainty.
The third methodology is more complicated and less intuitive to many. This method is referred to as "material balance" and is based on the concept of mass balance. Simply put, the mass of anything in a container is equal to the mass originally in the container, less what's been taken out, plus what's been added in. Another way to think about it is if you have a large container of gas with a fixed, but unknown, size (like a propane tank for example) and you measure the pressure drop of the container as you pull out a known volume, with some knowledge of the expansion properties of the gas, you can back calculate the volume of the container.
Material balance methods are complicated and require a lot of data (historical production, reservoir pressures, physical properties of the fluids, drive mechanism, etc), but when sufficient data is available they can give very good results; however, if the data is not available or is of poor quality then the results can be misleading. Computer based simulation models are typically based on the material balance methodology. This methodology is nearly always utilized in conjunction with one or more of the other two methods and by comparing the results the evaluator can learn a great deal about the reservoir.
All of these reserve calculation methodologies have their strengths and weaknesses and it is the responsibility of the evaluator to determine the most appropriate method. Each method requires some degree of judgment on the part of the interpreter and it is important to know and understand the assumptions used and the potential errors that may result.
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