Sunday, August 3, 2014

Tech Talk - fracking tight sand and shales

The recent news that Saudi Arabia has not found natural gas to be as available as it had thought from its shale deposits, and is shifting to exploring for gas in their tight sand formations has not caught a lot of attention. But it is worth considering some of the aspects of this – and hence this post.

The Oil and Gas Journal define tight sands in this way:
The term tight gas sands refers to low-permeability sandstone reservoirs that produce primarily dry natural gas. A tight gas reservoir is one that cannot be produced at economic flow rates or recover economic volumes of gas unless the well is stimulated by a large hydraulic fracture treatment and/or produced using horizontal wellbores. . . . . . . . . Tight sands produce about 6 tcf of gas per year in the United States, about 25% of the total gas produced.
The production of natural gas from tight sands is different to that from shale sources, for, as the Canadian Center for Energy notes:
Initial production rates are low; however, productivity is long lived.
To understand why this is, and why this differentiates from shale production requires a little bit of an explanation.

Back in the time that the plants were growing that went on, over time, to produce the oil and natural gas we now extract, the surrounding ground was typically soil, with intrusions of sand as the tides and rivers shifted. As succeeding layers of ground covered these layers, so the soil turned into shale and the sands into sandstone. Sand particles tend to be more round, and so as the particles packed together the gaps between the grains provided space for the oil and gas to collect. Clay particles, that went on to form the shales, on the other hand are flatter and pack together more tightly. Further, while the sand formed continuous layers of material, with relatively few cracks, the shale, on the other hand cracked as it was compressed, dried and was squeezed – simplistically in the same way as the lake beds crack when they are exposed to the sun after a drought has driven off all the water.

The result of this is that the fine sands that formed into the tight sands have relatively low permeability – fluids within them find it difficult to get through the very narrow passages and driving pressures have to be high to overcome the frictional forces along these passages. At the same time, because there are relatively few natural fractures in the rock, artificial cracks have to be driven through the rocks, in order to provide enough large passage ways for the gas to escape. It still flows relatively slowly through the rock around these cracks before it reaches them, and this is why the production is relatively low, but continues over time.

On the other hand the shale structure holds much of the oil/natural gas in a different way. Firstly there are the natural fractures within the rock, which tend to run into one another, and which hold much of the fluid that is released early in the production of these formations. Secondly the rock immediately around the fractures has been itself fractured somewhat during the formation of the layer, and has a higher porosity (i.e. holds more fluid) and permeability than the central segments of each of the larger pieces.

To simplify the situation therefore, prior to hydro-fracking the natural gas in a tight sand is permeated relatively evenly throughout the rock (given the variety of the conditions that control rock structure over even relatively short distances). On the other hand the natural gas in a shale is preferentially concentrated in the natural fractures and the rock adjacent thereto.

So now a horizontal well is drilled along the rock, and, at intervals pressurized to drive fractures into the surrounding formation. The rock structural differences mean that the sandstone and the shale will respond differently. And a slight qualification at the beginning of the explanation, because of the length of the feed lines to the injection point where the fracture will start, the pressure rises relatively slowly on the rock, rather than with the sharp pressure spike from an explosive blast, which produces multiple fractures. (The use of a small shaped charge to induce the fracture by driving a small hole into the rock, will similarly only produce a single fracture extending out from the well bore for each charge).

Contrary to the pictures that are shown by oil and natural gas companies on how fracking cracks grow out into the rock, the cracks will not branch out under their own normal development. Crack splitting only occurs at relatively high energy transfer rates, when the crack speed reaches the maximum, and the crack has to bifurcate to absorb the input energy, those conditions normally will not exist at any distance from the wellbore.

What happens in the case of the shale formations is that the pressure opens the natural fractures in the rock and as these link together the pressure can open them over a significant volume of the rock, giving the equivalent spread of fractures away from the wellbore as the initial pressurized joints intersect others as the sand and fracking fluid migrate along the joints into the rock. Opening up these passages and giving access to the relatively higher porosity rock along their edges allows a relatively high rate of flow for the initial volume of natural gas which is found in these zones. But as they deplete, and the natural gas has to travel from the more central part of the shale blocks, so there is the dramatic drop in production which has been remarked by many (around 65% drop within the first year in some cases). Production continues to fall as the more easily produced volumes drain through the intersected fractures, and the residual production falls to a slight fraction of its initial value.

In contrast, the tight sand formation will flow in a different manner. Because of the low number of natural fractures and the lack of permeability changes along the joints, much of the channeling through the rock has to be put in place by the fracking process itself. Because there is much less collection of fluids into natural fractures (though there is still some) the initial production rates are not as high as they are from the shale formations, since the overall induced fracture density and dispersed penetration is not as pervasive. On the other hand once the fractures are in place, although permeability is low, if the formation does initially produce at an acceptable rate, it is more likely that the well will continue to flow with a lower, but steadier flow, than the shale well, and for a considerably longer time.

Thus the news that Saudi Arabia is now moving to try and develop their tight sand fields suggests that they will need to carry out much more extensive development in order to get the initial volumes of natural gas that they will need, but that once these wells are producing, that they will last longer than they would in the shale fields.

7 comments:

  1. went back and read your old Bakken posts, would love your insight into what NG in that region could look like in the next 10-15 years.

    ReplyDelete
  2. Is it possible to do a post on the Russian unconventional gas/oil deposits as well?

    ReplyDelete
  3. Patrick, they are still flaring a lot of the SD Natural gas, the problem is an economic one in some cases, there not being enough sustainable production to cover the costs of pipes, but regs are slowly changing that picture.

    Kostas - good idea I will work on a post, though it may take a little time.

    ReplyDelete