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