Sunday, September 27, 2009

A Look at Shell's Genex model

The recent paper by John Stainforth (Marine and Petroleum Geology 26, 2009, pp. 552–572) gave us a hint of how Shell models hydrocarbon generation and expulsion. I can't help but to comment a bit here. The paper begins by explaining the problems of other models, quote:

"Models for petroleum generation used by the industry are often limited by (a) sub-optimal laboratory pyrolysis methods for studying hydrocarbon generation, (b) over-simple models of petroleum generation, (c) inappropriate mathematical methods to derive kinetic parameters by fitting laboratory data, (d) primitive models of primary migration/expulsion and its coupling with petroleum generation, and (e) insufficient use of subsurface data to constrain the models. Problems (a), (b) and (c) lead to forced compensation effects between the activation energies and frequency factors of reaction kinetics that are wholly artificial, and which yield poor extrapolations to geological conditions. Simple switch or adsorption models of expulsion are insufficient to describe the residence time of species in source rocks. Yet, the residence time controls the thermal stresses to which the species are subjected for cracking to lighter species."

Kinetics: the paper shows the calibration of kinetic models to some "natural data" (his fig. 9) from an unspecified location (calculating a transformation ratio from rock eval data is a tricky business, and we understand big oil companies need to keep secrets). Below are comparisons of the Shell models with some previously published models. Keep in mind that there is always a range of kinetics for each type and natural data tend to have a lot of scatters.

For type I source, oil conversion only, there does not seem to be a big difference between the Shell model, BP model the IFP model. The Bohai model is derived from subsurface data fitted with the Pepper and Corvi (1995) scheme. The Green River model is from Lawrence Livermore labs.

Here is comparison of the type II sources. For oil only conversion (** denotes oil only), the Shell model requires a higher maturity, but it is almost the same as the BP class DE (a more gas prone type II) facies. When I threw in some sub-surface data points I have available, all of the models are reasonable within the variability of data. Note the oil only and the bulk (oil + gas) curves for the BP facies bracket the data set.

Now, lets look at type III source rocks. This is interesting! The IFP kinetics published more than 20 years ago does a better job fitting the Shell data than Shell's own model. Again, if I throw in some of my own real data for a type III source, you can imagine what they look like. Gee, why are my data always more scattered?

Expulsion model: Shell's expulsion model assumes hydrocarbon expulsion is a diffusion process. I like the behavior of the model in terms of the implications on composition of the expelled fluids and the time lag it predicts. I am not sure that we need to compare that with the simple expulsion models some commercial software uses. For expulsion volumes, the choice of a simple threshold model in the commercial software is advantageous that it provides quick answers (volumes and GOR) well within the uncertainty of the data and allows scenario testing and even probabilistic modeling of charge volumes. The Shell model may predict a different position the residual oil may peak in the source, but if you plot some real data, the scatter is a lot bigger than the theoretical differences.

This figure shows retained S1/TOC over an interval in oil window (VRo=1.0-1.2, type II source). We can not really see evidence of any of the expulsion flow mechanisms - Darcy flow or diffusion. The retained oil is probably mostly adsorbed in the organic, as it shows S1 plotted by itself is more scattered. The average 100-120 mg/g TOC is what the simple expulsion model defaults to, which is a good practical approach without dwelling on the exact mechanism. There has to be some free hydrocarbons in the pores as well that may allow Darcy flow.

Some recent data set has cast a serious doubt in all the expulsion models, including diffusion. In the gas producing Barnett shale (an oil source), the total current retained gas is in excess of 100 mg/g TOC. This is several times more than any of the models predict. The shale has been uplifted and no active generation is occurring. 

This paper is good research, and may give us some insights into the processes, but I am not sure I see anything that will change the way we rank prospects which I assume is our job as a petroleum system analyst. The paper lists several theoretical advantages of the Shell model, for example, expulsion during uplifting, the predicted composition, GOR profiles etc. But it seems to me non of these will make the any difference when we apply the models in exploration. His figure 13b predicts type I source rock expelling 1000+ scf/bbl GOR oils at very low maturity (VR<0.7%). Even if it is true, are we really going to try to find some of these oil fields (if it is not clear to you, the volumes expelled before VR<7% is almost nil)? The typical situation is that we may have some Rock eval data from wells drilled on highs we assume are the equivalent source rock in the kitchen. But the uncertainty due to this assumption can be huge. In the Dampier sub-basin of NW shelf Australia, plenty of oil has been found, while all available source rock data show a type III gas prone type. The actual source rock is rarely penetrated. Even if it was, it would be too mature to derive kinetics or even original HI from it. Seismic data will have roughly a 100 m resolution at the depth of the source, so we do not even have a good estimates of its thickness. What is the point of worrying about minor differences in kinetics?

As for expulsion during uplifting, I am not sure we can prove it with geological data. Since there is definitely expulsion before uplifting, additional volumes expelled may be trivial compared to the volumes expelled before cooling, or to the uncertainty in calculating the volumes in an uplifted basin. In addition, the other models actually do still expel some volume because the typical kinetic models do not shut off right away.

The paper's criticism of Pepper and Corvi (1995b) in that they did not show gas expulsion during oil window may not be accurate. As far as I am aware, the Pepper and Corvi source facies are all tuned to give appropriate GOR ranges during oil window, even if it may not be obvious on the mass fraction graphs in the original paper.

1 comment:

  1. I think it is important to be aware of the fundamental error in Stainforth's papers on petroleum expulsion; a wrong problem formulation (boundary conditions) that invalidates completely all the results; diffusion of petroleum in source rocks is a negligible process.

    Stainforth (in his original Paris Organic Geochemistry paper) assumes that most of the petroleum resides absorbed within the kerogen, i.e., a "solid" polymer solution (do not confuse with adsorption). This is probably not too far from reality in most oil-prone kerogen (before the polymer becomes so cross-linked it behaves more like a brittle mainly adsorbing material). However, to expel a petroleum fluid by diffusion in kerogen it is fundamental that the solid-liquid(or gas) equilibria are handled properly; otherwise one end up with thermodynamically impossible results as the calculation results of Stainforth.

    Let us look at Stainforths formulation. He define the problem as an ordinary diffusion problem (the only forcing is the fugacity gradient). At the boundary to the source in the carrier (where the source hits the carrier) he enforce a ZERO petroleum concentration. Hence, there is a huge concentration gradient, and he gets a large diffusive flux. Here comes the bugger of this meaningless boundary condition: the source at and close to the carrier develops a close to or at zero petroleum concentration. So how on earth can there be any expulsion of a free petroleum fluid if the concentration in the kerogen at the boundary is zero ??? !!!!!

    If there is any free petroleum at the source carrier interface, the kerogen MUST be saturated; otherwise there is no free petroleum fluid to expel ! It cannot be saturated at zero concentration !

    The whole thing is complete nonsense. Since the carrier must have free petroleum and be (at first approximation) in (steady state) equilibrium at the interface with the kerogen these calculations must include the phase equilibria between the kerogen-petroleum solid solution and the petroleum fluid.

    Then it also become clear that since petroleum is generated with (approximately) the same composition at a given time (and source thickness is not extreme), there will not be any significant vertical concentration gradients at all to drive an ordinary diffusion. Hence, as (too) politely pointed out by Michelle Thomas (Geochimica Cosmochimica Acta); if diffusion is a significant transport process, it must be mainly pressure diffusion; driven by gradients in partial (whatever: molar/molal..) volume of the diffusing molecules in their solution. However, if that is the case, we should see a unidirectional compositional gradient in source rocks, and this gradient should approximately image the swelling property of each molecule. Nobody has ever seen such compositional gradient. Also the optimistic fluxes calculated by Thomas, are far too low to permit the low petroleum retention one sees in expelling (not over-mature uplifted) oil source rocks.

    In fact observed gradients are only compatible with a bulk flow; the flow is too fast and on a scale that does not permit compositional equilibration.

    There are numerous similar issues in many of the available basin modeling codes. Many of them comes from push from the user to include the entire cocktail of processes that can be found in a dictionary. This leads to uncoupled or poorly coupled processes; many of which are evaluated at inappropriate scales. The big question is if it would be much more useful to completely separate routine applications from "research / experimental" applications. That could be an interesting thread at this blog.