Oil Biodegradation - Bacterial Alteration of Petroleum

Under certain conditions, living microorganisms (primarily bacteria, but also yeasts, molds, and filamentous fungi) can alter and/or metabolize various classes of compounds present in oil, a set of processes collectively called oil biodegradation. Biodegradation affects oil spills and surface seeps. Furthermore, as first noted more than 30 years ago, biodegradation also alters subsurface oil accumulations (e.g., Winters and Williams, 1969). Shallow oil accumulations (< 80 ^oC reservoir temperature) are commonly found to be biodegraded to some degree. In fact, the vast majority of the world's petroleum is severely biodegraded oil in the shallow, super-giant Orinoco and Athabaska tar sands in Venezuela and Canada, respectively (e.g., Demaison, 1977). Smaller, but still giant, accumulations of biodegraded oil occur elsewhere throughout the world (Roadifer, 1987). This article reviews the:

• effects of oil biodegradation on oil fluid properties (API gravity and viscosity),
• effects of oil biodegradation on oil geochemistry,
• conditions necessary for oil biodegradation, and
• current estimates of the rates at which these processes destroy oil under surface and subsurface conditions.

Effects of Oil Biodegradation

Biodegradation gradually destroys oil spills and oil seeps by the sequential metabolism of various classes of compounds present in the oil (e.g., Bence et al., 1996). When biodegradation occurs in an oil reservoir, the process dramatically affects the fluid properties (e.g., Miiller et al., 1987) and hence the value and producibility of an oil accumulation. Specifically, oil biodegradation typically:

• raises oil viscosity (which reduces oil producibility)
• reduces oil API gravity (which reduces the value of the produced oil)
• increases the asphaltene content (relative to the saturated and aromatic hydrocarbon content)
• increases the concentration of certain metals
• increases the sulfur content
• increases oil acidity
• adds compounds such as carboxylic acids and phenols

For example, in a set of genetically related oils from Oklahoma, Miiller et al. (1987) found the following changes in oil properties with increasing levels of biodegradation:

Sample Type	API Gravity	Sulfur (wt%)	Vanadium (ppm)	Nickel (ppm)
Non-degraded Oil	32	0.6	30.6	16.4
Moderately Biodegraded Oil	12	1.6	224	75.1
Heavy Biodegradation (Tar Sand)	4	1.5	137.5	68.5

Sample Type	Saturate	Aromatic	Polar	Asphaltene
Non-degraded Oil	55%	23%	21%	2%
Moderately Biodegraded Oil	25%	21%	39%	14%
Heavy Biodegradation (Tar Sand)	20%	21%	41%	21%

Vertical and lateral variations in oil properties (e.g., API gravity and viscosity) caused by spatial variations in the extent of oil biodegradation can be mapped throughout a field using a variety of geochemical tools. During field development, such techniques allow the targeting of "sweet-spots" (areas of less degraded oil) within an accumulation that has been affected by biodegradation (see Predicting Fluid Properties). Such vertical and lateral variations in the extent of biodegradation typical fall into two categories:

1. Variations due to distance from the oil-water contact. Because biodegradation occurs at or near the oil-water contact (e.g., Head et al., 2003), biodegraded oil columns commonly are compositionally graded, with the most biodegraded oil occurring near the oil-water contact.
2. Variations due to the "pulsed" nature of reservoir filling. Since the time scale of biodegradation (discussed below) is often similar to the time scale of reservoir charging (e.g., Larter et al., 2003), a biodegraded oil column may consist of a mix of oil that arrived first in the reservoir (here called the "primary charge") and subsequent pulses of oil that arrived later (here called the "secondary charges" to the accumulation). The primary charge may be more biodegraded than the secondary charge, since the primary charge has been subjected to in-reservoir biodegradation for a longer period of time. Therefore, depending on the migration pathways into the reservoir, vertical variations in the relative abundance of "primary" vs. "secondary" charges may cause vertical variations in the oil fluid properties (e.g., API gravity and viscosity).

During oil biodegradation, oil fluid properties change because different classes of compounds in petroleum have different susceptibilities to biodegradation (e.g., Goodwin et al., 1983). The early stages of oil biodegradation are characterized by the loss of n-paraffins (n-alkanes or normal alkanes) followed by loss of acyclic isoprenoids (e.g., norpristane, pristine, phytane, etc.). Compared with those compound groups, other compound classes (e.g., highly branched and cyclic saturated hydrocarbons as well as aromatic compounds) are more resistant to biodegradation. However, even those more-resistant compound classes are eventually destroyed as biodegradation proceeds. Larter et al. (2005) estimates that heavily degraded oils have typically lost on the order of 50% of their mass.

Peters and Moldowan (1993) proposed a 1-10 scale on which the extent of biodegradation of an oil can be ranked based on the analysis of the oil geochemistry (e.g., using the presence or absence of various biomarkers that have different susceptibilities to biodegradation, with "1" indicating very early degradation (partial loss of n-paraffins) and "10" indicating severely degraded oil).

The early stages of oil biodegradation (loss of n-paraffins followed by loss of acyclic isoprenoids) can be readily detected by gas chromatography (GC) analysis of the oil. However, in heavily biodegraded oils, GC analysis alone cannot distinguish differences in biodegradation due to interference of the unresolved complex mixture (UCM or "hump") that dominates the GC traces of heavily degraded oils. Among such oils, differences in the extent of biodegradation can be assessed using gas chromatography-mass spectrometry (GC-MS) to quantify the concentrations of biomarkers with differing resistances to biodegradation. The UCM present on the GC trace of a heavily degraded oil does not affect this GC-MS analysis.

Conditions Under Which Biodegradation Can Occur

Oil biodegradation by bacteria can occur under both oxic and anoxic conditions (e.g., Zengler et al., 1999), albeit by the action of different consortia of organisms. In the subsurface, oil biodegradation occurs primarily under anoxic conditions, mediated by sulfate reducing bacteria in cases where dissolved sulfate is present (e.g., Holba et al., 1996), or methanogenic bacteria in cases where dissolved sulfate is low (e.g., Later et al., 2006, Bennett et al, 1993).

Although subsurface oil biodegradation does NOT require oxygen, it does require certain essential nutrients (e.g., nitrogen, phosphorus, potassium), which can be provided by dissolution/alteration of minerals in the water leg (Larter, et al., 2006).

Empirically, it has been noted that biodegraded oil accumulations occur in reservoirs that are at temperatures less than 80^oC (e.g., Connan, 1984; Barnard and Bastow, 1991). At higher temperatures, it appears that many of the microorganisms involved in subsurface oil biodegradation cannot exist. However, not all oil accumulations at temperatures less than 80^oC are biodegraded. Wilhelms et al. (2001a, 2001b) proposed an explanation for this observation: those authors suggested that if an oil reservoir has been heated to more than 80^oC at any point since its deposition, then, even if uplift later reduces the temperature to below 80^oC, the "paleopasteurization" or "sterilization" of the reservoir that occurred at the higher temperature will have killed the organisms needed for oil biodegradation to occur after the basin uplift. Therefore, oil reservoirs that have experienced significant uplift may contain non-degraded oil, despite the currently shallow depth and low temperature of the reservoir. Apparently, "recolonization" of such "sterilized" reservoirs by bacteria is typically unable to occur. Wilhelms et al. (2001a, 2001b) supported this model with a variety of case studies of uplifted or "inverted" basins from the USA, North Africa, the Barents Sea, and the Wessex basins.

Because subsurface oil biodegradation does NOT require oxygen, and can occur at temperatures up to 80^oC, in-reservoir biodegradation can occur even at many thousands of feet below the surface (e.g., Parkes et al., 1994), as long as the geothermal gradient is sufficiently low, and nutrients (e.g., nitrogen, phosphorus, potassium) are available through the water leg.

Rates of Oil Biodegradation

Larter and Aplin (2003) and Larter et al. (2003) suggested rates of 10^-6 to 10^-7 /year for anaerobic in-reservoir oil degradation at 60^oC, and 10^-2 to 10^-1 /year for anaerobic oil degradation at the earth's surface.

The rate of petroleum biodegradation in the subsurface appears to be limited by available nutrients and temperature and NOT by the carbon source (e.g., Larter et al., 2001, 2003, 2006). Hence, the size of the water leg (which impacts nutrient delivery) impacts degradation rates. Larter et al. (2003) calculated that the:

"actual fluxes of hydrocarbons being destroyed in oilfields around 40-70 are around 10^-4 kg/m²/year of oil-water contact area with reservoir temperature controlling the actual degradation flux value".

Larter et al. (2006) proposed biodegradation rates in the range of 10^-3 to 10^-4kg petroleum per m² of oil-water contact (OWC) per year for fresh petroleum in clastic reservoirs, with the highest values occurring at temperatures <40^oC

It should be remembered that an oil accumulation may be affected by multiple oil alteration processes in addition to biodegradation (e.g., Milner et al., 1977). For example, water washing, multi-stage oil charging, and evaporative fractionation can all affect the composition and fluid properties of an oil accumulation that is undergoing biodegradation. Oil geochemistry analyses can be used to decipher which combination of these alteration processes has affected the physical properties of an oil.

Understanding oil alteration processes, such as those listed above, provide the key to predicting spatial variations in fluid properties (API gravity and viscosity) within an oil field or within a series of stacked petroleum-bearing intervals (e.g., McCaffrey, 1996; Smalley et al., 1996; Koopmans et al., 2002). For information on how oil geochemistry (oil fingerprinting) is used during field development to predict vertical and lateral variations in fluid properties, see our article on Predicting Fluid Properties. Alternatively, contact OilTracers LLC by e-mail or by telephone at 214-584-9169.

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