Yibal is a classic example of the consequence, and suggests that the heroic efforts by Saudi Arabia are now hitting the same wall. Rapid depletion.
Sorry but this is wrong once again. Yibal is not at all like the Saudi reservoirs, the rock material is completely different and responds differently to fluid flow. The horizontal wells drilled in Yibal were not the same either, they are short-radius horizontal wells with single boreholes. If a fracture is intersected with that borehole water is coned into the borehole and well shuts down. The gas is still in the reservoir but due to adverse mobility ratio you can’t produce it from that borehole. The Saudi MRC wells are completely different. They have multiple legs, they are much longer in reach and as a consequence the well can be produced at lower drawdown which means it is less likely to produce water. The total ultimate recovery in Yibal is quite low wheres it is very high in most of the Saudi reservoirs.
It it obvious to anyone who has followed the peak-oil story that fracted horizontal wells are prone to the same EOR/tertiary phenomena--increased field production/accelerated field depletion and that anyone like Maugeri who doesn't recognize this is barking down the wrong christmas tree. I stand by my comments
Again, sorry but you are comparing apples and oranges and then applying logic based on banana peels. Shale is not like either the Yibal chalks or the Saudi mixed carbonates, its porosity and permeability, grain sorting, pore throat size etc are all completely different which means it will behave completely different during production. The production history for fraced horizontal shale wells is extremely well documented for many reservoirs with hundreds of well production profiles illustrating the exact same behavior, all of which is predictable. There is intial “flush” production, a hyperbolic quick decline but then a levelling out at a lower rate, that rate capable of being maintained for a number of years which is predictable based on type curve EUR. The levelling out rate is relatively low which is precisely why so many wells are required. As an example a conventional vertical gas well in an excellent reservoir may produce 10 BCF whereas a multistage fraced horizontal well in a shale might only have a well EUR of 2 BCF. This means that 5 horizontals would have to be drilled from the same pad to gain the 10 BCF equivalent of that vertical well in the conventional reservoir. The difference is that most of the shales have larger distributions areally and hence the ultimate reserves are larger, albeit recoverable at a greater cost. Because the wells are predictable and repeatable it comes down to managing costs and hoping for commodity prices high enough to meet hurdle economics. The press and blog sites have paid far too much attention to Arthur Berman’s views which are based on a very small subset of data which was available to him. As well one of his favorite observations was that his view was average well life would be 7.5 years. At 1 Mmcf/d that ends up being close to 3 BCF EUR which is quite respectable. Not all of the shales are created equal, some frac better due to higher silica contents, some produce at higher initial rates due to over-pressuring, some have better reservoir characteristics due to micro-intergranular porosities in forams etc. That being said there is no reason to expect the type curve analysis to be far off, it has proven to be pretty reliable “on average” and the shale production game is all about statistical means, not outliers. The main uncertainties have to do with reservoir anisotropies which cannot be identified by seismic (even shale reservoirs have changes laterally) and commodity price. You could argue that the only reason producers are still chasing shale gas at all is because they have commitments to maintain acreage and they see higher average returns due to liquid recovery. Gas on it’s own at current prices makes no sense in any of the shale plays.