Predicting Oil vs Gas in a Mixed Oil/Gas System

Fluid phase (oil, gas, oil and gas) in traps are usually not what the source rock has made through maturation process, and often far different from it. This is because of expulsion fractionation, migration lag, mixing of fluids from different sources, and phase separation during migration and entrapment (leak, spill) etc. Typical BPSM modeling does not model most of these processes correctly, or at all. 

In a D/E (deltaic coals as source rock), or a system with multiple source rocks, the most useful concept comes from Sales 1997 paper, that fluid phase often is controlled by  trap closure and seal strength, as shown in this figure:

In a dual HC phase system (reservoir pressure < Psat), if a trap's closure is less than the maximum column of gas the seal can hold, it will spill the oil phase and contain only gas (class 1). If the seal strength is less than a full oil column, it will retain the oil column, and leak off the gas (class 3). If closure is greater than the maximum gas column but less than the maximum oil column, it will end up with both phases (class 2). After J, Sales, 1997. 

Structure closure is often known at time of prospecting. Seal strength is not, nor is the fluid entering the trap, so the method we use is a Monte Carlo model that describes the unknow parameters, most importantly seal strength, GOR of incoming fluids (which depends on source rock type, maturation and migration process), and the saturation pressure of the fluids, with a distribution. The outcome of the modeling (Trinity software) is a probability of fluid type for each prospect/trap. 

 

The classic examples are found in deltaic basins in South East Asia. The discovery of Kikeh field rekindled the talk on this concept. Not too far, in the Mahakam delta, Kutei basin, Indonesia, there are several large/giant fields that are perfectly explained by this model. The structure closures range from 10s of meters to greater than 500 meters. The source rock is deltaic and fields are a mix of oil, gas and oil/gas. The figure below shows the model prediction using the same assumptions on 4 different fields. 

Trinity 3D phase risking results of four fields along the cross section (blue line) with same input parameters on charge (1000-10000 scf/bbl) and seal (25 to 120 psi seal Pc). Only variable is closure height among the traps. Map courtesy of Ramdhan and Goulty , 2018

It is important to note that the results are very good and not so dependent on the incoming fluid type. With the typical seal strength, the traps can be charged with 1500 scf/bbl black oil, or a 15,000 scf/bbl gas condensate, the end results is nearly the same. The high relief structures consistently yield oil phase or oil phase with a gas cap, and vise versa, that low relief structures are most often end up with a gas phase.  

I make this post because It seems to me that the last 25 years since the paper was published, there have not been enough application of this simple and very useful concept. Now we have a map based risking tool for easily making such predictions. Hope this will get more application of this unbelievably useful concepts.   

Discussions:

To be more generic, we can describe Sales classes mathematically between capillary entry pressure, fluid density and trap closure. For any given structure closure that is in the two-phase region (reservoir pressure below bubble or due point) of a petroleum system, the seal capacity dictates which phase ultimately remain in the trap, assuming charge volume is sufficient. 

Where, P_c is the capillary seal capacity of the shale, H is the closure (crest to spill point) of the trap,

⍴_w, ⍴_o, and ⍴_g are the in-situ densities of the water, oil and gas columns, respectively. 

Class 3 traps may often include a small gas column due to differences in interfacial tension between oil-water and gas water. Theoretically this may be 15 to 20% of the column see earlier post here. Some class 3 traps offshore Sabah (Kikeh and nearby fields) have variable small gas caps in stacked reservoirs. 

In the real world, many factors can affect the contacts and phase proportions, faults are prevalent in deltaic systems and can complicate leak/spill/closure relationships greatly, especially 3 way traps. Column may be dynamic from both rate of charge/leakage and changing composition of charge where gas is often not equilibrated with the oil column below. There is rarely enough data to validate, let alone predict such details before drilling.  However, for exploration purposes, Sales' concept, especially when combined with our probabilistic approach hold very well against observations. It is possible to include considerations of non-capillary seal, faults, and other factors in the input distributions. 

References:

Sales, J.K., 1997, Seal strength vs. trap closure ----, fundamental control on the distribution of oil and gas, in R.C. Surdam, ed., Seals, traps, and the petroleum system: AAPG Memoir 67, p. 57-83

Ramdhan1, A. & N. R. Goulty, 2018, Two-step wireline log analysis of overpressure in the Bekapai Field, Lower Kutai Basin, Indonesia. Petroleum Geoscience online article.

 

Phase Behavior of Mixed Petroleum Fluids

I came across this phase diagram recently and like to explain what I see. What is this fluid, what are the likely properties, and what geological processes may have created it? I posted on LinkedIn as a question and had many good suggestions that I have incorporated in the explanation below. 

1) It is obviously a gas (vapor) reservoir by definition (reservoir temperature > critical temperature), and a retrograde one (reservoir temperature < cricondentherm), definitely not an oil. See definitions of fluid types in the blog post just below. 

2) It is not a normal retrograde condensate. First, the critical point is at -92 °C, that is colder than pure methane (perhaps some nitrogen may be mixed in there)! So it is a lean gas. The actual C6+ is only about 2 mol% - so it is actually very dry.

3) The cricondentherm (the highest temperature on the curve) for a normal dry gas should be near 0 or negative, but this one is at 380 °C! That is a cricondentherm for a black oil. High cricondentherm means it takes very high temperature to vaporize the liquid in this fluid - so it must be fairly heavy hydrocarbons. 

4) The dew point pressure is abnormally high at ~8000 psi. High Psat gas means either it has a lot of liquid (rich), and/or the liquid fraction in fluid is hard to dissolve in the gas.

5) We can rule out rich liquid case because the critical temperature is too low for that a rich condensate. 8000 psi is also too high for that too. So it is likely a mixture of a lean/dry gas with a liquid that is much heavier than normal condensate. 

6) In this particular case, it is a dry gas sourced from a coal mixed with small amount of lacustrine oils. The "condensate" is around 35 API gravity! 

7) Very high saturation pressure (some times > 12,000 psi) is a good indicator of a mixed fluid that came from very different sources. We see this in the GOM deep water, and the Mediterranean Sea, where we have mixes of biogenic gas and some normal oil. We also find these on both side of Atlantic margins, and some deep basins in China. It is one of the clues for some of the fluids offshore Guyana/Suriname.

8) This could also be a result of a dry gas with oil based mud contamination , as proposed by Brian Moffat in the LinkedIn comments section. So be careful.  

The figure below explains the effects on phase diagram when a dry/lean gas is mixed with a normal oil. 

Fig. 2. Effects of mixing dry gas with normal oil on phase diagram. Dry gas has a very low critical temperature and cricondentherm. Black oil has very high critical temperature and cricondentherm. The mixed fluid inherits the low critical temperature from the gas, but the high cricondentherm from the oil. The saturation pressure increases dramatically as the two fluids are not compatible. It takes higher pressure for them to dissolve each other.  

Petroleum Reservoir Fluid Types

The five main type of reservoir fluids, black oil, volatile oil, retrograde gas, wet gas and dry gas, are used mainly by engineers for designing production facilities based on what is expected to happen to the fluid during production. It is often confusing to geologists as we tend to focus on the range of properties of each fluid type, such as API gravity, GOR and color etc. offered in literature tables like this one: 

However, the classification does not actually depend on these properties, instead it depends on the fluid's phase behavior and initial reservoir PT conditions. The same exact fluid can be a retrograde gas, or a volatile oil simply due to a few degrees difference in reservoir temperature. A fluid may be retrograde gas at a given reservoir temperature, but a wet gas if the reservoir temperature is higher. These typical ranges of properties are only a guide. In nature some gas fields have heavy condensates (<40 API gravity), whereas some black oils are colorless and very light (55 API). I hope this essay can help the PSA community in their petroleum system evaluation and communicate with engineers and managers better.

Fig. 1. The standard fluid types are determined by the position of the initial reservoir PT condition relative to the fluid's critical point, cricondentherm and separator conditions. The color circles on each line is the critical point. The large blue dot is the initial reservoir pressure and temperature. The blue line indicates how reservoir pressure decreases during production. Tc -  critical temperature, Tct - cricondentherm, Pd -- dew point pressure, Pb -- bubble point pressure.

The standard fluid types are determined by the position of the initial reservoir PT condition relative to the fluid's critical point, cricondentherm and separator conditions (Fig. 1). If reservoir temperature is lower than the critical temperature of the fluid it is oil (liquid), and when pressure drops it will cross the bubble point and thus also called a bubble point fluid. If the reservoir temperature is higher than the critical temperature, it is a gas (vapor), and also called a dew point fluid. Black oil and volatile oils are separated by the shrinkage factor (FVF) ; Among the gas types, it is called retrograde gas if condensate can form in the reservoir (Tc < T < Tct). If condensate cannot form in the reservoir (T>Tcc), but can in the separator, it is called wet gas. It is dry gas if no liquid drops out at the separator or surface. 

Black Oil is a bubble point fluid whose critical temperature is much higher than the reservoir temperature (Tc>>T).  It is "low shrinkage" - with FVF (or Bo) less than 2 due to low GOR. It is usually black hence the name. 

Volatile Oil is also a bubble point fluid (Tc>T). But the critical temperature is closer to reservoir temperature. It is high shrinkage (FVF > 2.0) due to higher  GOR and volatile because it has higher content of C2-C6 hydrocarbons.

Retrograde Gas (or Gas Condensate) is a dew point with critical temperature less than reservoir temperature (Tc<T) but because cricondentherm is higher than reservoir temperature (Tct>T)  condensate can form in reservoir when pressure drops below dew point and cause production problems. However, condensate volume decreases again (retrograde) when pressure is further reduced.   

Wet Gas has a dew point as well, but because reservoir temperature is higher than the cricondentherm (T>Tct), condensate cannot form in the reservoir when pressure decreases. However, because the separator PT condition falls within the phase envelope, condensate will form in the separator and has to be dealt with. 

Dry gas has so little C7+ that the condensate will not drop out in the separator or even at surface. 

Exceptions and odd fluid properties

The properties of fluids within each type can be outside or typical ranges given in the table above. There can be a black oil with no color, and 55 API gravity. Some gases may have a low gravity and dark colored condensate.  

The boundary between black oil and volatile oil is not so clear cut with parameters. GOR for volatile oils can be as low as 1000 scf/bbl, and black oil up to 2000 scf/bbl, depending to a large degree on the concentration of C2-C5 hydrocarbons vs methane.  The solution gas for black oil stays in gas phase in the separator, and simple mass balance equations (black oil models) are adequate. Solution gas from volatile oils drops condensate in the separator, and requires more sophisticated EOS models. 

Fig. 2. Normal relationship between API gravity and GOR. Fluids outside of the normal trend are likely formed under certain geological conditions, that may not happen to most fluids.

Certain geological processes can create unusual fluids. For example, when a gas condensate migrates into a low pressure reservoir, the light gravity condensate drops out and forms an "oil" rim. If the trap then leaks off the gas cap, or if the oil rim migrates into another trap, we can end up with a low GOR black oil but very light (something like 300 scf/bbl & 55 API). Water washing can cause a gas condensate to lose most of its gas and form a black oil as well. These “black” oils are light colored or colorless. The laminaria fields (fig.2) are black oils interpreted as formed by water washing of an originally gas condensate fluid. 

The opposite can happen when mixing very different fluids. We are now drilling much deeper (higher pressure) than before.  A migrating undersaturated gas may dissolves a small amount of normal or even heavy oil during migration, either from background organic matter, or small oil accumulations. The result can be a gas reservoir with a condensate API gravity in the black oil range. Such fluids have abnormally high dew point pressure and cricondentherm, so they likely fit the definition of retrograde condensate, but GOR can be in the dry gas range. 

Abnormal fluid properties can be clues to the geological processes, and the interpretation can be useful in petroleum system analysis and prospect evaluation. 

Other names

Gas condensate often has the same meaning as retrograde gas, but also a more generic term that include all gases because all natural gases have some amount of condensate, however little it may be. Sometimes is is also called condensate gas.

Rich gas condensate is one that contains more condensate. At a GOR of 5000 scf/bbl, a million cubic feet of gas yields 200 barrels of oil (condensate from the gas). The mass fraction of the two are about same (50% each), but both dollar and calorific/BTU value of the condensate are more than that of the gas. Even at the GOR of 20,000 scf/bbl, the 50 barrels of condensate at $70/bbl, is worth more than 1 mmcf of gas at $3/mcf. For us geologists, we need to be aware that rich gas condensate can only be found at deep enough reservoirs. 

Super critical fluid, is gas condensate (but typically refer to liquid rich ones) when reservoir pressure and temperature are higher than critical point. These have properties between gas and oil and some times called dense fluid. Near critical fluid can also include volatile oil.  

References:

William McCain, The Properties of Petroleum Fluids, 2nd Ed., 1990

Petroleum Migration Rates and Distances

 In my training classes, I am often asked about the rate and distances of oil and gas migration. There seems to be much confusion in understanding how petroleum migrates, and the controlling factors. 

Migration Distance

Long distance migration are observed in many basins. Here is a list of basins I am familiar with:

• Athabasca field, Alberta basin, Canada > 700 km from the kitchen
• Orinoco oil field,  Venezuela, > 100 km  
• East Texas field, Texas, USA, > 100 km 
• Wolfcamp accumulations near outcrop in central Texas, Permian basin, > 200 km.
• Rubiales field, Llanos basin, Colombia > 100 km
• Mississippi oil trend in Kansas, Anadarko basin, > 500 km 
• Ghawar field, Saudi Arabia, > 200 km. 
• Oil fields in Saskatchewan ( Viewfield,  Cactus Lake ...) and Manitoba (Sinclair), Canada migrated from the Williston basin, North Dakota, >100 km. 
• Illinois basin, oil pools > 200 km away from the mature New Albany source rock.
• Hangjinqi gas field, Erdos basin, 130 km based on maturity analysis.

Most of these are from Foreland basins or continental sags which have marine depositional systems with good vertical seals, and the structure relief is too low to allow vertical migration. Another requirement for long distance migration seems to be the source rock - enough petroleum needs to be available to feed the migration chain.  

Below are two figures from the Anadarko basin in Oklahoma and Kansas.

Figure 1. oil and gas wells in the Anadarko basin. The accumulations in Kansas are 100s of kilometers north of the Woodford kitchen in southern Oklahoma. The oil production trend (a giant "river" of oil migration) continues further north into Nebraska.  

Figure 2. Map location of wells in the Anadarko basin, showing patterns of migration into Kansas and beyond. The orange outline is the mature kitchen of the Woodford shale, which is the main source rock for the oil in the basin. There is also production in Nebraska, Colorado that are not indicated here.

Large vertical distances are associated with very good source rock potential and the geological controls that limit lateral migration (such as high structure relief, faults, and salt), and may be then limited by the thickness of the sediment column. In the GoM basin discussed above, sea bottom seeps are very common, the source rock is 10 km below surface. 

Migration Rate

Below is a typical burial history diagram from deep water of Gulf of Mexico basin. It shows that the "oil window" is roughly 10 million years. The Tithonian source rock is excellent (~ 100 m thickness, TOC ~6%, HI ~600mg/g ) with an UEP of about 10 m³ of oil per m². Assuming a porosity of ~10%, this converts to a flux of 1 m³ per million years, and a flow rate of about 0.00001 m/year for primary migration. Imagine it taking a year to move from one clay sized pore to the next! The capillary number Ca, is about 10^-15, ten orders of magnitude too low for viscosity to have any effect, so no Darcy flow! Note that the GoM has one of the fastest burial rates in the world, and most basins will have rates 10 times slower.

Figure 2. Typical burial history from deep water of Gulf of Mexico basin. The main generation window occurs over about 10 million years.

Similarly we can infer rate of secondary migration or charging, again with an example of a large accumulation and fast generation rate.  A one billion barrel field filled over 10 million years equates to 100 barrels (16 m³) per year. Even if the charge is occurring over a 1 square meter area (which is unrealistically too small), the rate is still slower than typical glacier, and 4 orders of magnitude too slow for Darcy flow. 

A related question is whether oil generation is fast enough to create micro-fractures. If we take the 1 m³/my rate generated, and calculate how much volume is generated per unit rock volume, we come to 1/100/1000000 = 1e-8 m³/year per m³, or 0.01 cc/m³/year.  A drop is 005 cc, so one drop every 5 years. You see where I am going. 

Flow Mechanism

On a related subject, some authors have suggested that Darcy flow be used to explain/model the higher saturation in some source rocks. I think it is just a misunderstanding of Darcy behavior. If we examine the geology of these source rocks, such as the Eagle Ford shale, the higher saturation in these source rocks is a result of the source rock being sandwiched in between tight limestones which act as seals. The source rock needs to build up saturation (higher local capillary pressure) to exceed the seal capillary entry pressure for primary migration. In areas where the seals are not present, the saturation is very low. The Eagle Ford is underlain by the Woodbine sandstone in East Texas, where the Eagle ford is not a good unconventional target. The oil expelled downward into the Woodbine and migrated up dip to accumulate in the giant East Texas field. Vast majority of source rocks in the world, such as the well known CT & A source rocks in the Atlantic margins, the Kimmeridge clay formation in the North Sea, and the lacustrine source rocks in the Bohai basins are also excellent source rocks but have very low saturations shown by the fact that S1 Rock Eval extract correlates very well with TOC. It indicates that the residual oil is mostly adsorbed by the organic matter. 

Another argument against using Darcy model for unconventional settings, is that if Darcy (viscous, transient) flow is the mechanism, we would expect high saturation in source rocks in younger basins. On the contrary, most unconventional plays are in old basins, and some of which have had no deposition (and therefore HC generation) for over 100 million years.

Source rocks are not homogeneous, and there are always some inter-bedded capillary contrasts over the thickness of the source rock, so some saturation is often necessary for primary migration, and often higher in the middle due to having to overcome addition capillary barriers to reach the edge. Migration will be from high saturation toward low saturation, so both up and down from the middle of the source rock. It is not a viscosity (Darcy) effect as the capillary number is just orders of magnitudes too low. The capillary contrast within a source rock are much, much higher than buoyancy - so downward migration is pretty common. See this post on that.

Simple experiment/Analog for Migration

Here is something you can try or imagine. Take a bottle of water, walk outside and pore it on the street. It will flow down the street, may be for a few feet. Then it will stop. Right? Then take another bottle and pore it at the same spot, the water on the street will start moving again, a few feet further, and stops again.  The distance of migration is related to the amount of water you have (UEP of the source rock), and the rate is related to how fast you can pore it (rate of generation). If there is a big pot hole, it will not continue further down until it is filled. This is how I think of migration, the roughness of the street surface mimics a capillary system, with small pools and barriers between them, when additional water is added, it allows the small pools to connect and flow continues, and then when you stop adding water, the barriers between the pools will hold the water in place, and flow stops. 

Phase Separation & Implications in HC Migration

Here are two videos of CCE (constant composition expansion) PVT test videos kindly provided to us by Murray Macleod at Core Labs Perth. These tests are used by engineers to determine bubble or dew point pressure (pressure at which the single reservoir fluid becomes two phase). In this blog I would like to talk about the implication of this in HC migration process. I hope this helps those geoscientists not so familiar with PVT/phase behavior. I wish I had learnt this earlier in my career as a petroleum geologist. 

In the CCE tool, the rotating cylinder moves away to expand the volume of the chamber thus lowering the pressure. The first video shows what happens to a single phase volatile oil when pressure is decreased from 8000 to about 1000 psi. At about 3300 psi (which in a basin would be at about 2200 meters depth), vapor (gas) bubble begins to form (hence the term bubble point pressure). 

As pressure is further reduced,  more and more gas comes out of the solution and takes up the upper part of the chamber and the volume of the liquid decreases significantly (by a factor of more than 2 in this case). What is not obvious (and important for exploration) is that along with that the gas oil ratio (GOR) in the liquid also decreases. 

The following figure shows the path of the process in a geological setting. Following the 3 green circles from deep to shallow, the starting volatile oil (deepest green circle) has a GOR of about 2300 scf/bbl. During upward migration, phase separation starts when it reaches about 2200 meters. As the oil continues to migrate to shallower depth, it loses more and more gas. At the shallow depth, the GOR becomes 300 scf/bbl (a black oil). 

The lost gas may get trapped in small traps along the way, so we end up with an low GOR oil accumulation. Or if enough of the gas makes to the final trap, we may have a gas cap. If the trap is not able to support the column of oil and gas to spill point, it may leak the gas and retain only the low GOR oil. Or if the seal is very good but the trap is small, all of the oil may spill, and we end up with a gas accumulation. 

Again, let me be clear, although the source rock may have supplied a high GOR oil, the final trap may be a low GOR oil accumulation, or a gas accumulation, or an oil accumulation with gas cap. It is determined by the seal and the reservoir pressure!

A similar process applies to gas condensate fluid. Below is a CCE video for gas condensate. As the pressure decreases to dew point, a liquid phase forms at the bottom. The liquid volume increases as pressure decreases and more liquid comes out solution from the vapor phase. The GOR of the vapor increases (CGR decreases). Like the oil case, you may deduct what can happen at the final trap following the red circles in the figure above. Depending on if it leaks or spills, the trap may end up with a higher GOR gas, or a low GOR oil, or both. Check out the AAPG paper by John Sales (1997).    

If the starting fluid has a GOR between 3000 and 4000 scf/bbl, whether it is called oil or gas depends on what engineers find in the CCE test. If bubbles form at the top, it is called an oil, and if liquid forms at the bottom, it is called a gas condensate. This is how engineers decide if a field is called oil field or a gas condensate field. Note that even at 4000 scf/bbl, there is still more what geochemists call oil (C6+) in the fluid than gas (C1-5) in weight.   

Please let me know what you think by commenting, thanks!

Zhiyong He,

ZetaWare, Inc. 

Is Uplift/Erosion A Significant Risk for Petroleum Systems?

When the basin experiences uplift and erosion, the source rock may cease to generate hydrocarbons, and structures formed afterwards may not receive charge; existing oil accumulations may form gas caps, and gas caps may expand and cause oil to spill; reservoirs may get too shallow and oil may get biodegraded; seals may become ineffective and the accumulation may be completely destroyed. Given these reasons, you would think it would be hard to find oil and gas in such basins? 

Lets first look at it not from the tradition process driven perspective but from a statistical one. More than 80% of the world's petroleum reserves are found in basins with uplift and erosion (well, I did not calculate the precise percentage, but just thinking of North America, Venezuela, Russia, the middle East, North Africa, etc.). So if had all the knowledge we have before any petroleum had been found yet, we would have had a much higher chance to find oil and gas fields in an uplifted basin, than one that is not.  

The petroleum industry began in the 19th century in Pennsylvania/Ohio, in the Appalachian basin, and the first well found oil at just 20 meters below surface. The basin has been uplifted since 200 my and between 3 to 5 km of sediments have been removed, which is why the oil was found at such shallow depths in the first place. The petroliferous basins in North Africa have experienced two significant erosion events, on in Hercynian, and then more recently during the Alpine orogeny (figure 1). Yet some of the biggest fields are found here, such as the Hassi Messaoud and El Borma. In the US, the giant East Texas oil field (10 billion OOIP), and giant Hugoton gas field (80 TCF) are both very shallow due to uplifting since Cretaceous time; and the list can go on and on. It seems to be a rule, rather than exception with so many cases. It leads me to conclude that perceived risks of seal and timing in uplifted basins are probably unfounded. 

Fig. 1. Burial history in the Ghadames basin, where giant fields like the El Borma, and the famous Hassi Messaoud field are located. 

Perhaps the most extreme cases are found in the San Juaquin basin in California, where several billion barrel fields are found literally at surface, due to reservoirs outcropping at surface. The Midway-Sunset oil field shown in figure 2 below, and the Kern River oil field are just a couple of examples.  

Fig. 2. Midway-sunset oil field in the San Juaquin basin (John Borkovich, 2019 CA State Water Resources Control Board). More than 3 billion barrels of oil had been produced by 2006. Gusher image from Wikipedia.  

For my 35 years as a basin modeler and later a practical petroleum system analyst, what I have seen is that the experts who conduct research and write papers tend to study the problems from a scientific/process perspective, focusing on the details, but tend to not look from the perspective of analogs and statistics that may contradict their research. In the past 10 years or so, I have been paying more attention and finding contradicting evidence from analogs and large dataset against some of our common wisdoms or misconceptions, such as my earlier posts on gas risk due to high maturity, timing risk, biodegradation risk, etc. This post is just another example.     

Downward Migration: Observation and Mechanisms

by Zhiyong He, ZetaWare, Inc.

Observation:

I have been asked often in my training classes about downward migration. Is downward migration limited, or does it present a higher risk? What is the mechanism for large scale downward migration/charge? Is there a way to estimate the volumes for upward vs downward migration?

I want to start with observations. Many large accumulations have been discovered in reservoirs stratigraphically older than the source rock in many basins. Here are some examples that I am familiar with:

1. North Sea, Middle Jurassic and older reservoirs below the KCF 
2. North Africa, the Cambrian, Ordovician sandstone reservoirs in Ghadames, Illizi and Murzuq basins, below the Silurian hot shale source cock. The giant Hassi Messaoud field produces from Cambrian, some distance below the source rock.
3. Bohai, Oil fields in Paleozoic basement, “Buried Hills”, karst tomography, between and under the Tertiary grabens that contain the Oligocene source rock.
4. Similarly, the Bach Ho (White Tiger) oilfield in fractured granite basement underlying Oligocene source rocks in Vietnam. 
5. The biggest oil fiend in the United States lower 48 is the East Texas Field (> 10 billion barrels) that produces from the Woodbine sandstone directly below the Eagle Ford source rock. 
6. The biggest oil field in Anadarko basin is the Oklahoma City Field which produces from the Ordovician Wilcox formation, charged from the Devonian Woodford source rock above.
7. In California, the giant Midway-Sunset oil field also produces from the Temblor formation below the Monterey source rock.  
8. Muddy/Dakota reservoirs underlying the Mowry shale in Powder River basin. 
9. Cambrian and Ordovician oil and gas fields charged from the Utica source rock above in Ohio and Indiana, of the Appalachian basin. 
10. Three forks reservoirs and the Bakken source rock above in Williston basin.
11. The Norphlet plays in onshore Mississippi, Alabama and more recently the Eastern GoM deep water where the Smackover is the source and the seal.  
12. The Tuscaloosa sands below the Tuscaloosa Marine Shale (TMS)
13. La Paz field, Maracaibo basin, Venezuela. Reservoirs are Cretaceous limestone and fractured granite basement, below the La Luna source rock.  
14.  The Augila-Naafora field, Sirte basin, Libya. Cretaceous source rock above and onlapping onto basement reservoir and provides the seal.
15. Suban gas field, South Sumatra, Indonesia and Adang Utara oil field in Malay basin, producing from basement.
16. The Paleozoic reservoirs (Sarah, Qasim, Saq) below the Silurian Qusaiba source rock (Hot Shale) in Saudi Arabia. These reservoirs produce super light oils in the western part, that may have been water washed, and gas condensates in the deeper eastern region.  

Some other observed characteristics are:

• The source rock is often also the seal 
• Reservoirs can be separated by one ore more shales/sands from the overlying source (eg. North Sea and Williston basin). 
• In some cases, lateral juxtaposition across faults may help explain accumulations, and some are harder to explain. 
• Check out this paper on basement fields around the world.  

Downward Migration Mechanism

I would explain downward migration as driven by the natural capillary process. The figure on the left below shows the typical capillary curves of a reservoir and a shale (source rock). The shale has a very steep curve and pressure increases quickly with HC saturation. The center and right figures show the theoretical capillary pressure (difference between the HC phase pressure and water pressure,  Pc = Po-Pw), profiles before and during HC generation. 

Fig. 1, Capillary drive mechanism for primary migration. Pressure in the non-wetting phase HC is higher due to saturation increase cased by HC generation.

During generation, as oil saturation increases in the shale, so does capillary pressure and the oil near the sand is pushed into the sand due to capillary pressure difference: energy/potential for the non-wetting phase HC fluid is much lower in the sand than in the shale.

1. Oil saturation and therefore capillary pressure in the center of the shale is higher as it is further away from the sand. Pc can be several hundred psi even at 20% oil saturation.
2. Saturation at the boundary stays low as it is easier to expel due to the sharp gradient in Pc.
3. Buoyancy gradient for oil (~0.1 psi/ft) or gas (~0.3 psi/ft) is much smaller compared to capillary gradients ( which can easily reach several hundred psi over the half thickness of the source rock)
4. Capillary pressure is in addition to any pressure increase due to hydrocarbon generation, or compaction. And it is a higher in magnitude force than both over the source rock thickness. 

Additional Controls

The above assumes a homogeneous layer of source rock. In nature, the source rock may vary vertically in pore sizes. If the source formation is deposited as a fining upwards sequence, the capillary pressure is higher at the top with smaller pores. This will cause more volumes to migration downward. 

If the source rock is overlain by a tighter formation, and underlain by a good reservoir, nearly all the volume will migrate downward. This may be the case with the biggest oil field in the lower 48 of US, the East Texas field. The Woodbine sandstone reservoir sits directly below the Eagle Ford source. The tight Austin chalk is above the Eagle Ford. 

If the source interval has inter-bedded silty zones, hydrocarbon saturation in the more porous zones will be higher in order for the Pc to exceed the sealing capacity of the tighter zones. This essentially creates the favorable condition for a unconventional play.  Check out this post for more on this. 

Overpressure and the "centroid" effects of carrier beds may further enhance downward migration. The figure below is after the North Sea, and the Norphlet examples. The water pressure in the source rock is expected to follow the regional compaction driven over pressure. The sand below has limited vertical extent, which causes the classic centroid pressure effect. The pressure in the sand will follow the line parallel to the hydrostatic pressure, but higher. At the deeper end, usually the HC kitchen, the shale is more over pressured than the sand below, and the resulting hydrodynamic force will help downward migration.  

Fig. 2, Effects of over pressure on primary migration. Downdip area of the carrier beds are under pressured relative to the source rock. At the crest, the opposite is true, which may limit column heights of accumulations.

Accumulations usually occur at the shallow end, and some volumes migrated below the source rock may leak up to younger reservoirs. Note that Both capillary force and centroid pressure drive help upward expulsion as well, if the sand is above the source. 

Discussions:

Human intuition is that we want to quantify the volumes that migrate upwards vs downwards, especially as a basin modeler. The uncertainty is large. I would simply assume that roughly 50% of the volumes should migrate downwards if the reservoir is directly below the source rock, plus/minus the uncertainty, more if there is a tight formation above the source rock. If the reservoir is further down stratigraphy, the risk goes higher, as it may need to rely on juxtaposition, or coarsening downward stratigraphy, etc. No, the modeling software cannot tell you this (whatever the vendor may claim their software can do), you have to make such arguments, or assumptions, like most things with basin modeling. 

Limited columns in Northpet traps:

• Some have observed that Norphlet play seems to have limited column heights compared to structure closure, and have suspected that it could be due to the limited efficiency perceived of downward migration.  Steve Walkinshaw observed that the Norphlet sand only has a oil column if the overlying Smackover porosity is filled, or where the Smackover is tight (http://www.visionexploration.com/norphlet.htm), implying that it may be volume limited.   
• My own interpretation, based on concepts given this presentation and my other presentations on seals/column height and charge limitation, is that these could be seal capacity limited. Where the Smackover is tight, it is simply a better seal. In my observations and estimates, where column height is less than the trap closure, it is often are often limited by the seal capacity, rather that charge volumes. We may find stacked pays with similar columns.  In some cases, we may find an empirical correlation between column heights and effective stress.  
• In general, volume can be limited if the fetch areas are small or the source rock is very weak. However, in majority of cases, trap sizes are typically much smaller than the estimated change volumes.
• We may never know the reason for sure in a particular case. So we should use any empirical rule of thumb we can find if it helps to reduce risk. Meanwhile, we should continue to look for evidence, correlations and new explanations.  

Conclusions:

• Downward migration should be very effective as large scale forces exist to drive downward migration.
• If the reservoir/carrier is directly below source rock, chance of charge should be high as evidenced by the examples of several prolific basins. 
• Lateral juxtaposition across faults may be helpful, especially for migration into reservoirs further down stratigraphy, but it is not required for sands directly below the source rock. 

Where Did All The Gas Go?

This is my summary of the same titled LinkedIn post, where I asked for analogs of known gas fields that are interpreted as sourced from an oil prone source rock due to high maturity. We have received more than 130 comments, and 13,000 views at the time of this post. I want to thank all who participated in this crowd wisdom experiment.   

The background is that we have all come to use to burial histories and maturity maps from basin models showing oil and gas windows. Particularly, gas windows colored in red are giving exploration managers a heartburn. In recent years as we started to look at petroleum systems from the top down, the large dataset of basins and fields globally show that the organo-facies dominantly control what fluid type we find in the basin. The second most significant factor we find is the reservoir pressure (pvt control), in conjunction with seals that determine oil vs gas in traps in a mixed source environment. The effect of thermal maturity, which the original schematic diagram from Tissot et all were meant to show, plays only a minor role. 

Figure 1. Traditional concept of oil/gas windows may have led to over-emphasis on maturity in our industry. Cumulative expelled products from Pepper and Corvi 1995 organo-facies  give more appropriate basin wide GORs, that are strongly a function of organo-facies, rather than maturity.
 

As the figure above shows, cumulative fluids expelled from the different organo-facies (Pepper and Corvi, 1995) differ greatly, and the proportions of oil and gas are very consistent with observations of accumulated fluids in basins regardless of maturity of the source rock. In short, we find that basins with very oil prone source rocks, such as the Tithonian of the GoM deep water, KCF of the West of Shetland, SHJ of the Bohai basins, have little or no gas discoveries although the source rock were over mature before the reservoirs were even deposited. On the other hand, basins with only gas prone source rocks have essentially no oil discoveries such as the Southern North Sea, areas of South China Sea, Rovuma Basin of Mozambique, and the Nile delta of Egypt. In basins with mixed oil and gas accumulations, as in many South East Asia basins. we find that the type of fluids and their properties are more controlled by the pvt conditions of the reservoirs, rather than maturity.    

Figure 2. The contracts among three different petroleum systems. The Nile delta has almost no oil fields, and the Gulf of Suez has almost no gas fields. The Western Desert has mixed oil and gas fields. Of course all three basins have part of the source rock in "oil window" and part in "gas window". The fluid types seem independent of that. 

The commenters provided quite a few potential examples, that I have tried to further look into and continue to learn about. Here I will attempt to group them in my proposed explanation to limit the length of this post. They fall into the following categories:

1) Some of the examples are from basins with mixed source rocks, such as the North Sea, which has the well-known oil prone KCF, but also the gas prone Heather, and potentially Paleozoic coals. The Western Desert of Egypt falls into this category (left side of figure 2). These are basins with mixed oil and gas fields, and as I will discuss below, PVT conditions may be an important control. 

2) Some very large gas fields at shallow depth may be formed by phase separation. The Hassi R'Mel in Algeria may be explained as a Sales 1997 class I trap where significant solution gas in oil was released as oil migrated to shallow depth and displaced the oil. Similar large gas fields include the Hugoton field (largest gas field in North America), and the Troll field in the North Sea. These fields are less than 1500 m deep, and all have an oil rim. Based on standard PVT diagrams, at about 2000 psi in reservoir, any charge between 400 scf/bbl and 60,000 scf/bbl will result in a dual phase reservoir. Although in these examples, a partial contribution from a more gas prone facies may not be ruled out, the shallow depth (low pressure) have made fluid phase almost independent of the charge from source. Some of the shallow Eastern Siberia oil and gas fields, many of which are dual phase, may fall in to this category.  

Figure 3. Phase diagram. Green curve is the Glaso (1980) bubble point and red dew point curve of England (2002). At reservoir pressure of 2000 psi, any incoming fluid between 400 scf/bbl and 60,000 scf/bbl will form a dual phase trap. Whether the gas phase, or the oil/condensate phase is preserved depends on the seal capacity and trap closure. Chance of both preserved is very high due to the density differences.

 3) Some of the gas fields, such as the North field in Qatar (largest in the world) and the Astrakhan in Russia, the Rimbey gas field at the deep end of the Leduc reef trend in Alberta, the Norphlet trend in Alabama and the Sichuan gas fields. The commonality of these are they are associated with carbonates, in which thermal cracking of oil can be greatly accelerated by TSR. These fields are all sour (high H2S and CO2). Cracking to gas at oil window temperatures make it likely to happen during migration. In the case of the North field and the Permo-Triassic gas fields in southern Iran and the UAE, there is also evidence that they may have been generated by a low quality Qusaiba facies.    

Figure 4. Effect of TSR on thermal cracking of oil to gas. Gas condensate can be formed at much lower temperatures compared to normal cracking kinetic models. Data from Zhibin Wei et al. 2011.  

4) As usual, these are not the only possible explanations, and often several factors contribute. The main point of this post is that it is relatively rare to find conventional gas accumulations due to a very good oil prone source rock being over mature. The exception being when we started drilling very close to the source kitchen, maturity does come into play. The deeper sub salt fields in the Campos basin offshore Brazil, such as the Pão de Açucar, the Austin Chalk play near the Eagle Ford gas window, and the Elgin-Franklin fields in the North Sea, are examples. These tend to be condensate rich (100-200 bbl/mmscf) as supposed to dry gas. Of course if our target is the source rock itself, we would expect to find gas in the gas window.  
 
The WoS Application

Here I would like to use the example of the West of Shetland basin to demonstrate how to analyze a petroleum system from the top down when traditional PBSM modeling does not provide the answers. The WoS is a Jurassic rift basin in the north Atlantic, and the Kimmeridge Clay formation is an excellent marine source rock. Much modeling work has been focused on the complex thermal history, with rifting, and Eocene volcanism, the source kinetics, the suppressed vitrinite reflectance ..., but have not explained the fluids in the basin.  

Figure 5. Basin modeling results of the WoS. Timing of oil generation predates the deposition of reservoirs. Present day thermal stress is at ~240 C. Note the source rock is not present in the green area. Burial history and maturity map courtesy of Julian Moore.

 The models predicted that the source rock was in the oil window near the end of Cretaceous, and very post mature today. Yet the basin contain mainly oil fields. And the system GOR (adding all gas and oil reserves) is less than 2000 scf/bbl, consistent with the Pepper and Corvi 1995, class B organo-facies. 

Figure 6. The basin hosts several large oil fields, some of which have small gas caps, and some scattered small gas condensate fields. The GOR of these fields plot on a simple phase diagram. PVT data courtesy of APT UK/Julian Moore 

The top down method as applied here is this. Since the source rock is a very oil prone one, with hydrogen index up to 1000 mg/gTOC. The bulk of the accumulations should be oil, regardless of maturity or timing. The GOR and API gravity of the oils should increase with depth due to various reasons, such as migration lag effects, gravity fractionation, and bubble point controls, as shown in figure 6, on the right.  The small gas fields are likely result of phase separation, rather than maturity, and the GOR for those are higher at shallow depth due to dew point control. J. Sales 1997 concept may be at work here, that small traps on spill path will have phase separated gas, whereas large relief structures should contain oil. That is what has been observed here. 

Zhiyong He,

ZetaWare, Inc. 

References:

He Z. and Murray A. (2019) Top Down Petroleum System Analysis: Exploiting Geospatial Patterns of Petroleum Phase and Properties. AAPG Search and Discovery, #42421

Pepper A. and P. Corvi, 1995, Simple kinetic models of petroleum formation. Part III: Modelling an open system. December 1995 Marine and Petroleum Geology 12(4):417-452

Sales, J.K., 1997, Seal strength vs. trap closure—a fundamental control on the distribution of oil and gas, in R.C. Surdam, ed., Seals, traps, and the petroleum system: AAPG Memoir 67, p. 57–83.

Oistein Glaso, 1980 "Generalized Pressure-Volume-Temperature Correlations," Journal of Petroleum Technology. 

England, W.A., 2002, Empirical correlations to predict gas/gas condensate phase behavior in sedimentary basins, Org Chem 2002, 33(6):665-73

Wei, Z. et al., 2012 Thiadiamondoids as proxies for the extent of thermochemical sulfate reduction, Organic Geochemistry, 44 (2012) 53-70

Does complex geochemistry of an oil mean a multi-stage filling history?

In the last few years Zhiyong and I have talked a lot about “top down” petroleum systems, analysis (e.g. He and Murray, 2019), one aspect of which is “geochemical inversion”.  Petroleum is a natural material containing 100’s of thousands of individual compounds, mostly hydrocarbons.  Although the composition is complex it is not random: it encodes signals inherited from the original organic matter as well some related to thermal or biological processes during or after formation.  Geochemists interpret this to provide information on the origin and history of a reservoir fluid.

However, I get nervous when the results of geochemical inversion suggest complicated charge histories which are not matched by an equally complicated geological/tectonic history. Recently I reviewed a paper which suggested eight discrete charge events had contributed to the fill for a cluster of fields. The corresponding burial history looked fairly simple so it was hard to imagine how charge could be anything but smooth and continuous in the area. I have a feeling that interpretations like this arise from a lack of recognition of how heterogeneous fluid compositions can be, even in well-connected reservoirs, charged slowly and continuously by a single source rock.

 

In an AAPG talk last year (Murray and He, 2020) we noted that it is quite common for the oil underlying a gas cap to be undersaturated with gas. This shouldn’t be surprising, given that the rate of filling – which is limited by the rate of kerogen maturation during burial - is of the same order of magnitude as the rate of diffusion driven mixing.  If the kerogen organofacies is not uniform (normal for fluvio-deltaic and fluvio-lacustrine source rocks in particular), and fluids are not fully mixed, we would not expect the fluids in the reservoir to be uniform either. Furthermore, since fluids are expelled over a source rock maturity range from ~ 0.7 to 1.3% Ro (vitrinite reflectance), we would not expect to find a uniform “maturity” signal in most oils either, whether it is based on methylphenanthrene isomer ratios or gasoline range ratios or whatever.

 

My experience of reservoir geochemistry studies, where samples from multiple depths, units and wells within a single field are examined, mostly confirms these expectations: A lot of fields I have looked at do not contain well-mixed fluids, independently of any physical compartmentalisation that may exist. This is hardly a new observation: England (1990) commented on it in relation to the Forties field for example. Indeed, it is more surprising when reservoir fluids are found to be well mixed.  I have seen examples of this too though and it seems to be when (a) geometric factors in migration homogenise fluids before or during their arrival at the trap or (b) thermal disequilibrium accelerates density overturn via convection and therefore mixing. My colleagues and I described the latter process in respect of the remarkably well mixed fluids in the Sunrise gas-condensate field (James et al., 2010). Well-mixed fluids are also quite common in fractured carbonate reservoirs where mixing pathways are short due to polygonal fracturing.  My point in mentioning the unmixed fluids is that geochemical inversion studies frequently base their conclusions only one sample from each particular field or reservoir, without taking this into account.

 

A specific example of geochemical inversion is the interpretation of patterns of biodegradation in terms of reservoir temperature vs. charge history.  Biodegradation, which occurs at temperatures lower than about 80 °C, has easily recognisable effects on oil. The most characteristic feature is the complete or partial loss of the n-alkanes (also called n-paraffins). These straight-chain compounds are easily assimilated by bacteria and gas-chromatograms of biodegraded oils show their depletion relative to the “unresolved complex mixture (UCM)” hump.  Note that no new material is formed here – bacteria do not convert straight chain hydrocarbons into the branched and cyclic hydrocarbons comprising the UCM – the latter are just more resistant to attack. A chromatogram of a crude oil with complete loss of n-alkanes is shown in figure 1.

Fig. 1   Gas chromatogram of a severely biodegraded oil from the Vincent Field, Australia (Murray et al., 2013)

A so-called “polyphase” or “hybrid” oil is one in which it is suggested that more than one discrete charge/biodegradation event occurred. This is usually based on the simultaneous presence of very easily degraded and very resistant compound. An example is the co-occurrence in an oil of n-alkanes and the 25-norhopanes, a group of pentacyclic terpane biomarkers associated with a severe level of biodegradation (Peters et al. 2005 and references cited therein). The n-alkanes are attributed to a component of the charge arriving after the reservoir temperature exceeded 80 °C when biodegradation stopped.  A similar conclusion is sometimes drawn when the gas chromatogram shows prominent n-alkanes on top of a large UCM, as shown here in figure 2.

Fig. 2   Gas chromatogram of a “polyphase” biodegraded oil from the Lady Nora Field, Australia. MCH is methyl cyclohexane, a cyclic alkane which is relatively resistant to degradation

Back in 2005 I worked on a heavily biodegraded oil field in the Middle East.  Being onshore and shallow it had been pattern drilled and there were a lot of samples to play with. Gas chromatograms showed the usual UCM with n-alkanes and resolved peaks from other simple compounds present to variable degree. There was a good correlation between API gravity and the area of GC-resolved peaks relative to the UCM, as shown in figure 3.

Fig. 3   Correlation between the total area of resolved peaks (relative to the UCM) and API gravity of oils from a large oil field in the Middle East region

This correlation was useful in estimating the API and the viscosity (by another correlation) of fluids for which there was insufficient sample for direct measurements.  However, in order to predict bulk properties away from well control, we needed to understand the factors controlling the extent of degradation.  Because there were spatially coherent differences in the degree to which light vs. heavy “fresh” charge overprinted the UCM, I concluded, at the time, that there were multiple stages of charge and degradation. The problem was that the burial history was simple and charge should have concluded more than 100 Ma before present.  At the time, I thought there must have been things in the charge history – perhaps to do with “motelling” or some other migration-related process  - that were not captured in the charge model. However, I revisited the report recently and realised there is another possibility. It goes like this…

 

Several studies have shown that heating of the asphaltene fraction of a heavily biodegraded oil can release fresh oil, complete with the original complement of n-alkanes (Snowdon et al. 2016 and references therein).  Asphaltenes are macromolecules with a composition and molecular structure similar to that of the kerogen from which they were derived (Snowdon et al. , 2016). Laboratory pyrolysis of asphaltenes is thus akin to the artificial maturation of kerogens. Figure 4 shows gas chromatograms (and density, viscosity) of a heavily biodegraded oil from a field in the Middle East region, before and after heating at 300 °C for 12 days and at 350 °C for 10 days.  The thermal stress from these two heating regimes is equivalent to a vitrinite reflectance of 0.8 and 1.3% respectively. 

Fig. 4   Gas chromatograms for the original oil from a large oil field in the Middle East region and after heating as shown. I.S. is the “internal standard” added to assist quantitative analysis

If we can do this in the laboratory, why would it not also happen in nature as a reservoir containing biodegraded oils is buried deeper?  Let’s consider such a reservoir which is continuously buried so that the temperature increases from 80 °C to ~ 120 °C over a period of about 20 Ma. Using the kinetics of asphaltene conversion from laboratory studies, we can estimate that about half of the mass of asphaltenes would be converted to “fresh” oil.  The chromatogram, perhaps like that in Fig. 4B, would show a “polyphase” character, without the requirement of any new charge arriving from the source rock after biodegradation ceased. 

 

What if the reservoir is not heated as high as 120 °C? Could we still get an apparently polyphase oil? I believe so: Some studies (see Snowdon et al., 2016 and references cited therein) have shown that the source of fresh oil in asphaltene heating studies is not only pyrolysis (i.e. the breaking of high-energy covalent bonds). Rather, the cage-like molecular structure of asphaltenes appears capable of encapsulating some of the original oil and preventing it from being biodegraded in the first place. This oil can be released by thermal disruption of the asphaltene clusters at temperatures lower than those required for pyrolysis. Figure 5 shows before and after heating chromatograms for a crude oil which had been severely biodegraded at the surface (following an oil spill). The conditions used, 320 °C for 2 days, create a level of thermal stress similar to that applied to the oil in figure 4B. However, in this case the post-heating oil has lots of n-alkanes and only a very small UCM. I wonder how much of the fresh oil here has been released prior to pyrolysis temperatures being reached.

Fig. 5   Gas chromatograms for the original, biodegraded oil collected after a spill at sea and after heating at 320 °C for two days (from Oudot and Chaillan, 2009)

In almost all cases where complex charge histories are invoked to explain geochemical anomalies, I can (at least in principle) explain them by things that happen during, normal continuous burial and supply of hydrocarbons. This doesn’t mean that the simple explanation is necessarily true - just that, in the absence of evidence for a complex burial/thermal history, we need not be as puzzled as I was back in 2005.

 

As with all these blog posts, I invite and indeed welcome push back/comments/clarification. They are not peer-reviewed papers, just some observations and thoughts from one individual.

Cheers,

Andrew Murray,

References:

England W. (1990) The organic geochemistry of petroleum reservoirs. Org. Geochem., 16, 415-425

He Z. and Murray A. (2019) Top Down Petroleum System Analysis: Exploiting Geospatial Patterns of Petroleum Phase and Properties. AAPG Search and Discovery, #42421

James B., Bailey W, Murray A., Pelechaty S., Kaiko A. and J. Li (2010) Unusual reservoir connectivity revealed by data integration at the Sunrise Field.  APPEA J. 50th Anniversary issue, 349-370, Australian petroleum production and exploration association (A PDF is available from the author on request)

Murray A. and He. Z. (2020) Oil vs. Gas: What are the Limits to Prospect-Level Hydrocarbon Phase Prediction? AAPG Search and Discovery, #42513

Murray A., Dawson D.A., Carruthers D. and Larter S. (2013) Reservoir Fluid Property Variation at the Metre-scale: Origin, Impact and Mapping in the Vincent Oil Field, Exmouth Sub-basin. Proceedings of the Western Australian Basins Symposium, Petroleum Exploration Society of Australia, Perth, August 2013 (A PDF is available from the author on request).

Oudot J. and Chaillan F. (2009) Pyrolysis of asphaltenes and biomarkers for the fingerprinting of the Amoco Cadiz oil spill after 23 years. Nature Precedings. 4. 10.1038/npre.2009.2975.1

Peters K. E., C. C. Walters and J. M. Moldowan, 2005, The Biomarker Guide: Cambridge University 479 Press, Cambridge, U.K., 1155 p.

Snowdon L.,  Volkman J.K., Zhang Z., Tao, G. and Liu, P. (2016). The organic geochemistry of asphaltenes and occluded biomarkers. Org Geochem., 91, 3-15.