Broadly speaking, there are three main reservoir characteristics that matter to production. The character of the reservoir rock, the composition and purity of the crude, and the strength and nature of the drive mechanism all influence the flow rate and ultimate productivity of a reservoir. Reservoir depth, orientation, and complexity are also important in that these factors impact the cost and complexity of drilling, as does the composition of the cap rock and other matrix through which drilling must occur.
>>Reservoir rock characteristics
Though often referred to as underground pools of oil, reservoirs should not be conceptualized as large voids filled with crude. A better description is that reservoirs are subterranean expanses of rock whose pore spaces and fractures are saturated with some combination of oil, water, and other elements and molecules. It is better to think of reservoirs as rock sponges rather than underground milk jugs.
The two main characteristics of reservoir rocks that matter most to production costs, and ultimately to production rates, are porosity and permeability. Porosity and permeability are the two most important of reservoir rock characteristics. Together they influence the amount of trapped hydrocarbons and the rate at which the hydrocarbons will flow during primary production. The pore space in highly porous reservoir rocks allows them to hold more hydrocarbons (and also water), while the permeability of reservoir rocks impacts flow rates. The vast majority of reservoir rocks are sedimentary rocks, but highly fractured igneous and metamorphic rocks sometimes contain substantial reservoirs as well.
Porosity is expressed as a percentage and is calculated by dividing pore volume by total volume. Porosity depends on grain shape and and to a lesser extent on grain sorting. The theoretical upper bound of porosity is 48% for perfectly spherical grains of equal size. Evenly eroded particles will be more spherical in shape, while less eroded particles are more angular. The ‘porosity cutoff’ is defined as the minimum porosity considered viable from an economic perspective, and porosity cutoff values vary by rock type. Typically, the porosity cutoff for sandstones is 8-10%, and the porosity cutoff for limestones is 3-5%. Limestone’s lower porosity cutoff values reflect the propensity for limestones to be highly fractured. In addition, the porosity cutoff depends both on the depth and the “economics of the well” – the costs of production and market price for that particular crude stream (Hyne p. 156). As the price of crude rises, it makes economic sense to produce from less porous, or ‘tight’, reservoir rocks. In order to produce ‘tight’ formations, the rock must first be fractured, and this process is both energy intensive and costly. I will discuss this process in greater detail in the section on production.
Absolute permeability is measured in Darcies or millidarcies, and is often referred to as perm or perm K. Technically, a darcy is “the permeability that will allow a flow of 1 cubic centimeter per second of a fluid with 1 centipoise viscosity (resistance to flow) through a distance of 1 centimeter through an area of 1 square centimeter under a differential pressure of 1 atmosphere” (Hyne p. 157). From this definition, we see that low viscosity hydrocarbons (those with few carbons but a high carbon to hydrogen ratio) will flow at higher rates than the “barbed wire” asphaltenes. As a consequence, we can also deduce that in complex crude streams, early production will favor the lighter hydrocarbons and later production will be more highly comprised of heavy crudes – a very important factor to keep in mind as we examine models that forecast production rates at the global aggregate level.
While absolute permeability concerns a single fluid moving through rock, relative permeability concerns the relative movement of a fluid (hydrocarbon) through rock when another fluid (typically briny water) is also present. Relative permeability ranges from 1.0 (when there is only on fluid) to zero. The relative permeability depends on the ratio of oil to water, but it also depends on the absolute difference in viscosity between the crude stream and the brine. The relative permeability of heavy crude streams is decidedly less than that of light crude streams. From this fact we can deduce that as a reservoir ages, that is to say as production from a single reservoir progresses over time, not only will the crude stream become more viscous, the watercut (percentage of water produced with the oil) will increase.
The permeability of a source rock is primarily a function of two variables: grain shape, and grain sorting. Because these are the same variables that influence porosity, we see that permeability is strongly correlated to porosity, but highly porous rocks can have little or no permeability if the pore throat (the constriction between grains) is small. Conglomerate source rocks have low permeability, while well worn and sorted sandstones have high permeability. While rocks with very low porosity are by definition highly impervious, hydrocarbons can flow relatively quickly through the fractures in highly fractured rock.
Sandstones, limestones, and dolomites are the most productive reservoir rocks, and within group variation of porosity and permeability is greater than between group variation. Roughly half of all producing source rocks are sandstones. Limestones and dolomites make up nearly all of the difference (Hyne 2001). Because the volume of dolomite is less than that of calcite, the replacement of calcite by dolomite increases the pore space by 13% (Schlumberger online oilfield glossary). In addition, dolomites, like limestone, have a propensity to be highly fractured. Hence, dolomites make some of the most productive reservoir rocks. Conglomerates, igneous rocks, and metamorphic rocks can also produce at high rates provided they are highly fractured.
At the opposite end of the spectrum, siltstones and shales can be hydrocarbon rich, but because they are very low porosity and have a perm K values near zero, the hydrocarbons are trapped in place. Unless they are fractured (either through natural processes of folding or through mechanical processes like hydro-fracing) shales and siltstones will not flow.
>>Composition of crude
A wide mix of hydrocarbon types, from methane to asphaltenes, are found in every crude stream or reservoir (a single subsurface accumulation of crude which is physically separated from other reservoirs and has a single natural pressure system). As Hyne puts it, in addition to the hydrocarbon molecules, “all sorts of cats and dogs can turn up in a hydrocarbon reservoir, whether it contains oil or gas or both. Along with natural gas and its natural gas liquid constituents, other gases can present themselves. Carbon dioxide (CO2), oxygen (O2), nitrogen (N2), and hydrogen sulfide (H2S) are the most common” (Hyne 2001, p. 65). In addition to these gases, reservoirs also contain metals, salts, sulfur, and nitrogen (elements which often attach to the hydrocarbons themselves). For this reason, every reservoir is unique, and crude streams are typically characterized and priced by a set of easily measured characteristics: specific gravity, viscosity, sulfur content (often described as ‘sweet’ or ‘sour’), nitrogen content, pour point, and flash point.
The weight, or specific gravity, of a crude is expressed in ºAPI (read: degrees API). The arcane formula for generating the ºAPI value reveals this measure to be inversely related to specific gravity. The higher the specific gravity, the lower the ºAPI.
ºAPI = (141.5 ÷ specific gravity) – 131.5
Using this formula, we can calculate the ºAPI of water (specific gravity = 1) to be 10. Crude streams which have a higher specific gravity than water, like bitumen (a common term for asphaltic crudes), will have a ºAPI value less than 10. Very light streams have higher values (sometimes in excess of 50).
The weight of a crude gives an indication of its hydrocarbon composition. Light crude streams tend to have a larger number of liquid paraffins, while heavy crude streams have a much higher asphaltic content. Within the industry, five classifications are generally employed to describe a crude stream. In order from heaviest to lightest, we have bitumen (<10 ºAPI), heavy crude oil (10º to 20º API), medium crude oil (20º to 35º API), light crude oil (35º to 50º API), and condensate (º50+ API) (Raymond and Leffler 2006).
Light crude streams “almost always command a higher price than heavier crudes” because they produce higher cuts of gasoline through fractional distillation, and, at least here in the U.S. where most cars run on gasoline rather than diesel, the gasoline cut offers the highest crack spread (the difference in price between equal volumes of crude and petroleum products) (Raymond and Leffler 2006, p. 64).
Heavy crudes are also highly viscous. They do not flow as easily, hence heavy crudes are more costly to move once they are produced. High viscosity crudes also challenge production as well because large, complex hydrocarbons have a much more difficult time squeezing through the pore throats of reservoirs. As heavy crudes are heated, the viscosity is lowered. You can see this by heating olive oil into a cold pan. As the oil heats up, it’s viscosity decreases. Heavy crudes must sometimes be either heated or mixed with lighter crudes in order to flow under normal atmospheric conditions. This is especially in cold climates.
Waxy crudes have a relatively high pour point – the lowest temperature at which a crude stream will still pour before it solidifies. Pour points vary between 125ºF and -75ºF (Hyne 2001). Like heavy crudes, waxy crudes with very high pour points must be treated in order to flow easily under normal atmospheric conditions.
The sulfur content of crude streams is also measured as a percentage of ???. Crude streams with a high sulfur content, are colloquially referred to as ‘sour crude‘ while those with a low sulfur content are referred to as ‘sweet crude’. The etymology of sour and sweet modifiers is indeed derived from their flavor. In an earlier era, when the most value petroleum product was kerosene (i.e. lamp oil), products with a high sulfur content would create a non-odoriferous scent when burned. The best test of sulfur content that a purchaser could make was to literally taste the kerosene. If a sour flavor was detected, the sulfur content of the kerosene was high.
What the public did not know at the time was that the off-putting scent was sulfuric acid, a long-recognized environmental pollutant. Through the combustion process, sulfur combines with oxygen creating sulfur dioxide (SO2). When sulfur dioxide is released into the atmosphere, it combines with water (H2O) and produces sulfuric acid which materializes as acid rain. Recognizing this effect, the sulfur content of refined petroleum products is regulated, and, therefore, sulfur must be removed from crude.
For various reasons, sulfur content of crude has increased over time. Produced sulfur must be separated from the hydrocarbons which leaves the problem of what to do with all that sulfur. One idea is to form the sulfur into giant blocks, and use these sulfur blocks to build modern day pyramids like the ones that are currently being erected in Canada.
Carbon dioxide (CO2) is often dissolved in the produced hydrocarbons. In addition to being a greenhouse gas, carbon dioxide is also an agent of corrosion (source ???). For this reason, carbon dioxide is removed from the crude stream at the site of production, liquefied, and reinjected into the reservoir.
>>Water-Oil Ratios, Watercut, and Relative Permeability
Water is present in nearly every hydrocarbon reservoir, and as a consequence, water is produced along with oil in nearly every well. The water-oil ratio influences production in five important ways.
First, salt content of the briny water accelerates the corrosion of all the equipment that it comes into contact with.
Second, the water which is produced must be separated from the oil. In cases where the water and oil are emulsified, the separation occurs in eumlusion heater treaters. When water is not held in suspension, it separated in a horizontal free water knockout separator.
The third important way that watercut influences the cost of production is that the water produced contains environmental contaminants (like heavy metals and sulfur). The water must either be re-injected or treated. In some cases, re-injection is not feasible, and the producer must treat the water.
The fourth important way that watercut can impact production costs occurs in wells that are low pressure and high temperature – conditions which are “ripe for free water and natural gas to form hydrates, a slushy mass that can plug flow lines… Remedies include keeping the gas warm – above the hydrate dew point” (Raymond and Leffler, p. 192).
The fifth important way in which water influences production is in the production rates themselves. When watercuts – the ratio of water production to total production – are high, the total volume of crude produced will be far less than the quantity of total liquids flowing through the wellhead. Over time, as the watercut increases, a constant flow rate of total liquids will bear witness to declining production rates of crude.
The last few years have seen a dramatic increase in global water production. Globally, the average watercut is 75%, a 5% increase on watercuts 10 years ago. According to the Norwegian Petroleum Directorate (NPD), annual oil discharges to the sea total over 3,000 tons, with a water-to-oil ratio that increased to 1.2 in 2006 from 0.93 in 2004. This ratio is expected to increase even further. (http://www.roxar.com/oilinwater/)