Biodegradation Much? Common Wisdom vs Statistics

By: Zhiyong He, ZetaWare, Inc.

Many studies have shown that biodegradation can have significant impact on oil quality (eg. Larter et al, 2006, Yu et al 2002, Wilhelms, et al 2001). Peak degradation rates are around 30-40 degrees Celsius, which is roughly at about 1000 meters below mudline on average. How much is the risk (% probability) of finding heavy oil if we have a prospect at this depth? For practical purposes, lets say heavy oil means an API gravity lower than 20 API. This question was posted on LinkedIn as a poll, and the answers are anywhere between 10 to 90%, and the mode is around 70%. See the original post here  and many thanks for all who participated. 

Many of you know Andrew Murray and I have been working on examples and methods for Top Down PSA for the last few years. While looking for field/fluid data, I came across a paper titled "Properties of crude oils in Eastern Hemisphere" by Kraemer and Lane 1937. Having read the papers on biodegradation and developed a tool for modeling biodegradation in Trinity a while back, my first thought was that by 1930s the wells were probably very shallow and that many of them would be heavy oils. I was only right about the depths. It was very surprising that out of the 142 fields, less than 10% (13) had an API gravity of less than 20, as shown in the figure below.

The next paper I found was McKinney et al. 1966, which included fluid properties of 546 oil fields in the United States. The API gravity depth plot on the left shows the typical trend, that API in general decrease to shallower depth (Similar to figure 2, Larter et al, 2006). The figure on the right is the 359 fields shallower than 2000 meters. Only 18 (5%) of those are below 20. You can see most of the heavy oils are from California. Most of them are probably sourced by the well known Monterey Fm, which belongs to organo-facies A, perhaps that is (at least partly) the reason for the low gravity (and often high sulfur). Texas and Louisianan have a lot of shallow fields but have no oils below 20. Reservoirs formation of some of these outcrop at surface not too far from the fields.   

Next I plotted a global data set of ~16,000 fields that are less than 2000 meters deep. 14% of the top 1000 meters are less than 20 API, and only 7% of those between 1000 to 2000 meters. The figure on the right include the deeper fields as well.

So what does this all mean? Globally the base rate of heavy oil at shallow depth where biodegradation is a concern is only 10%. If we were to only rely on a basin model that includes the biodegradation process, we are much more likely to predict a heavy oil at these depths.

It is possible that such field databases may not include some discoveries where oil is too heavy to be produced (therefore not counted).  But I don't believe that is a significant enough number to change the statistics because this is such a large dataset, and if it is a prevalent problem there would have been a lot of literature on it. Note that some of the large heavy oil pools are included such as the Athabaska, Orinoco, Rubiales and Kern River.

We are aware of other factors that may prevent biodegradation - such as OWC configuration, nutrient supply,  paleo-pasteurization, and timing of charge (duration of oil in reservoir), etc. Most of these are very hard to determine. The statistics above would imply the possibility that one or some of these factors are very prevalent in most basins. My own suspicion is that in in vast majority of cases/basins charging of shallow reservoirs are active at present day, due to migration lag regardless of when generation occurred.

The most important take away from this is that we should always check base rate (Bayesian analogs) when using basin modeling (bottom up) to predict fluid properties in prospects. Our models only include a small fraction of physical/chemical processes that happen in nature and much of the input of these models are assumptions due to lack of data, and lack of understanding. 

Select references:

Wilhelms, A., S. R. Larter, I. Head, P. Farrimond, R. di Primio, and C. Zwach, 2001, Biodegradation of oil in uplifted basins prevented by deep-burial sterilization: Nature (London), v. 411, p. 1034– 1037.

Yu, A., G. Cole, G. Grubitz, and F. Peel, 2002, How to predict biodegradation risk and reservoir fluid quality: World Oil, April, p. 1– 5.

Larter, S. R. et al. 2006, The controls on the composition of biodegraded oils in the deep subsurface: Part II-Geological controls on subsurface biodegradation fluxes and constraints on reservoir-fluid property prediction. AAPG Bulletin, v. 90, no. 6 (June 2006), pp. 921–938.

Kraemer A. J. and E. C. Lane, 1937, Properties of typical crude oils from the fields of the eastern hemisphere. Department of the Interior. United States Government Printing Office. 

McKinney C. M. E. P. Ferrero, and W. J. Wenger, 1966. Analysis of crude oils from 546 oilfields in the United States. Bureau of Mines. Untied States Department of the Interior.