The porosity of sedimentary rocks is reduced as function of depth due to an increased stress with depth. The stress increase cause an increase shear stress at the grain contacts which eventually cause grains to slide, the rock to compact and porosity to reduce. It is likely that an increased temperatur will speed-up the compaction process and therefore reduce porosity faster with depth for a high geothermal gradient than for a low geothermal gradient.

An increased temperature will likely also speed-up diagenesis in form of dissolution of grains and re-precipitation of the dissolved material filling-up the pore space. The problem wilth this process is that it will only reduce porosity if it is associated with compaction removing the pore space created by the dissolution process.

So yes it is possible that an increased geothermal gradient could cause a more rapid loss of porosity with depth nthan a lkow geothermal gradient. However, although I have looked at quite a number of reservoir rocks and reservoir settings I have never come across an example where I have observed that porosity is markedly reduced faster for higher geothermal gradients than for lower getothermal gradients.

Not necessarily. While formation temperature affects porosity through processes like compaction and diagenesis, the relationship is indirect and complex. As temperature increases with depth, porosity usually decreases due to compaction and cementation. However, in some cases, higher temperatures can create secondary porosity through the dissolution of minerals, especially in carbonate reservoirs. Factors like lithology, burial history, and fluid-rock interactions often have a stronger influence on porosity than temperature alone.

You might have to rely upon dynamic fluid & heat transport simulations and show that input models respecting static geological knowledge (e.g., realistic porosity / compaction trends) support your hypothesis.

From the perspective of a "reservoir scale" person, the balance between heat conduction and convection might determine the kind of observations you are making. But root causes would be in correlations between porosity vs. thermal conductivity and porosity vs. permeability. Beware of tensor (aka scale) effects (on permeability for sure). Support effects are probably tricky for representating convective cells. Motivations for correlations between porosity and permeability or thermal conductivity, etc. can be found in pore scale physics.

If the simple question is how to establish a quantitative correlation between geothermal gradient and porosity, then the simple answer is to make an analysis of porosity as function of net effective stress for the same type of rock in a number of basin settings with different geothermal gradients and then plot the porosity-stress functions on the same plot together with information about the geothermal gradients. If you can demonstrate on the plot that the porosity-stress functions gradually move towards lower porosity for a given net effective stress for an increasing geothermal gradient you will have the first argument for that an increased geothermal gradient will cause a faster porosity reduction.

But as many parameters control the porosity loss with depth I doubt that you will find a clear correlation between geothermal gradient and porosity-stress. So you will likely need as a second step to correct/normalize the observed porosity-stress functions for burial rate, hydrocarbon-history, shaliness, stress model (uniaxial, hydrostatic etc.) etc.

An alternative is to test core plugs in the laboratory and demonstrate that increasing the temperature will speed-up the compaction process. But here utmost care need to be exercised to insure that any change in temperature will not change e.g. stress and that the results are physically sound. You need e.g. to demonstrate thet the change in compaction rate will not cause that the porosity-stress gradient - after extrapolation to geological strain rates - can be substantiated by the observed porosity-depths in the subsurface which are the result of compaction at geological strain rates.

Regards

Finn Engstrøm

The greater porosity of rocks results in their lower heat transfer coefficient. Such rocks conduct heat worse due to air bubbles in the pores of the rocks. Such rocks are insulators, it is difficult to raise or lower their temperature. The factor that increases their heat transfer and ability to change temperature are fluids - most often underground water, but also crude oil. The factor replacing air in the pores of rocks is natural gas.

OK - I get your point. Higher porosity and gas filled porolsity will increase the geothermal gradient under the assumption that it is heat flow from below that generate the geothermal gradient. But your question was about the relationship between temperature (not temperature gradient) and porosity.

I agree with the previous answers, but would like to stress the importance of rock type or lithofacies when dealing with poroperm changes during burial. Finn mentions it in one of his replies. In my view, lithofacies are a first-order control of much of the diagenetic history of most clastics. Of course, temperature is important, and an elevated temperature is commonly the prime reason for low porosity and permeability (reservoir failure) in sedimentary basins worldwide. However, the issue for explorationists is about predicting which basins will likely see porosity preserved even in the face of relatively high geothermal gradients. To answer that question, we need to know the rock type or lithofacies because that sets up the textural and compositional factors, which greatly influence the diagenetic changes during burial. These variables are commonly either ignored or lightly dismissed when looking at poroperm prediction in basins. Looking through the literature at the hundreds of cross-plots of porosity vs permeability or porosity vs depth, we rarely see any plots expressed as a function of rock type or lithofacies. As a result, many of the conclusions made from these plots are meaningless because they are plots of very different rock types. Whether a sandstone is fine-grained or coarse-grained will have a fundamental control on its diagenetic history, including porosity and permeability. Whether a sandstone is an arkose with highly labile feldspars, or a quartzarenite and essentially "inert", will also significantly affect its diagenetic history. In other words, and to bring it back to the original question, if you are comparing porosity-depth trends between basins with different geothermal gradients, then you must separate the lithofacies in the data. In practice, this comes down to applying lithofacies to core/plug data. Sorting the apples and the oranges.