Alexander Khurshudov: Oil exporters don’t need to worry about shales renaissance
It’s been almost 7 years since I’ve been watching the production of American hard-to-recover reserves, which are commonly miscalled “shale”. No revolution happened due to them, but they stabilized production in the US for several years. If it were not for them, the Americans would have to import half of the gas and a three quarter of the oil consumed.
And now that the oil prices have established over $50 for a barrel, those eager for cheap oil lay all their hopes on the USA. They are expecting the shale companies to increase drilling and production, thus bring the oil price down. To evaluate the probability of this scenario we need to analyze the current state of the shale industry. And this is what we are going to do.
1. SHALE GAS
Although oil is more important and more expensive, I’ll start with gas fields. Because their widespread development started earlier, almost 9 years ago. Some of them are already depleted, and using them as an example we can predict (with some corrections) the future of the oil fields. The American Energy Information Administration EIA defines 7 majorshaleformations (pic.1), but we’ll also add the pioneer Barnett field in the North of Texas.
The main current indicators for the fields are shown in table 1. The data on the reserves, prices and production are collected from different EIA materials, in some cases they are converted for convenience. The data on the drilling rigs are taken from Baker-Hughes.
A quick look at the table 1 leads to the following conclusion. Barnett field is in the final stage of its development. Drilling isstopped, gas production is rapidly declining, though it is still quite feasible. Out of the 379 bcm of reserves not more than a half canactually be produced. So, the reserves appear to have been overestimated.
The same process is developing in Eagle Ford field, but quicker. Here there are oil and gas condensate zones, and most of the production is happening there. The initial reserves were also overestimated and with the current production decline (22% a year) they won’t be produced.
In Haynesville field the main shale occers at the depth of 3-4 thousand meters, but the overlaying beds also contain gas. After reaching the maximum in 2011, the production has been slowly declining, the initial production rate here is twice as low as in new areas. In general, the gas recovery corresponds with the reserves, so I assume that the recovery factor may even exceed the designed value.
Half of the shale gas in the US comes from Marcellus field. Last year the recovery of 186 billion cubic meters, which is 5.3% of global gas production, is expected there. There are some new reserves there, including those within the territory of New York State, where hydraulic fracturing is banned yet. With increasing gas shortage the ban will be lifted.
Utica field is adjacent to Marcellus. It is quite new, has been under development for just four years. The proved reserves have not been calculated yet, but the potential resources vary from 400 to 1100 bcm. It is still possible to select the most productive drilling targets, but the rate of drilling is several times lower that it was at the dawn of the “shale revolution”.
The other large fields (Bakken, Niobrara and Permian Basin) have low reserves and production levels of shale gas, drilling is stopped, so I didn’t include them in to the table. Now let’s look at the recent changes.
The beginning of last year became a nightmare for the shale companies. In February WTI price decreased to $26, followed by the drop to $60-70 for 1000 cubic meters of gas at the spot market. The prices hadn’t been that low since 1999. To make drilling a well economic with those prices, it has to produce over 100 million cubic meters of gas, but there are very few such wells in the shale fields. So, the producers continued to actively reduce drilling (pic.2) for 3-4 months, which led to 3% decline in gas production. In the summer the prices restored and even exceeded the previous year’s level, but the drilling hardly increased. Instead, the wells that had been drilled, but had not been completed earlier were extensively put into operation (pic.2). I’ll dwell on this in more detail, because there were a lot of speculations about this issue, which are far from reality, as it often happens.
Drilling an average well in the US, including obtaining mineral right, costs $6-7 million. After the target depth is reached and the wellbore is cased, the well is submitted to the customer and the drilling rig is moved to the next location. Perforation and the inflow stimulation is done by a different contractor, with a more mobile workover rig and their own equipment. The most important part of shale wells completion is a multistage hydraulic fracturing, the cost of which is considerable, provided there are 20-30 frac stages, and amounts to $1.5-2 million. So, a lot of reasons can be found to POSTPONE the completion of the well.
The reasons can be technical: the well may not be connected to a pipeline, the separation units may not have enough capacity, there is also an important reason such as “no money”. Such well don’t stay idle long, because it is wasteful to have no payback from the millions buried in the earth. It’s worse when the reasons are geological: the well happened to penetrate a thinner layer, which has too much clay or too few fractures, so a good inflow is not guaranteed at all. Such wells might stay idle for years.
In Russia this process is regulated and is called temporary abandonment. In the US the control over such wells seem to be weaker, but they are listed. Now let’s get back to the wells in Marcellus field (pic.2).
From June to November 223 wells were drilled in the field, but 300 wellbores were completed, because 77 wells were completed after temporary abandonment. Obviously, the best wells were selected; if all the suspended wells had been highly productive, they would have entirely stopped drilling for the year. Now 623 wells remain suspended, their future is unclear. Some of them will be activated later, when the gas prices rise. The others will wait for the abandonment, which also costs money, but doesn’t bring any profit whatsoever.
In general, there is about 1.9 trillion cubic meters of proved gas reserves in the five largest gas fields in the USA; with the current recovery rate they will be produced in 5 years’ time. With the gas prices increase the reserves may grow by 1.5-2 trillion cubic meters, but the gas production will still gradually decline.
2. SHALE OIL
At first glance the perspectives of shale oil are easier to assess since there are only four large fields (table 2). But it only seems so. Because there is a huge mess about the oil reserves calculations.
I, like any oil specialist, trust oil and gas volumetric calculations. This is a lot of work done by geologists, that incorporates the data on the field, its extent, water content, oil saturation, economically justified recovery factors. I quote the results of such estimations for Bakken and Eagle Ford fields. But shale fields are like hives, the situation there changes every day. One has only to get off the subject for a while and see: one well had the inflow more than expected, another – less than expected, yet another one didn’t have anything at all. And so the so-called “operational” estimations appear.
In their last operational assessment the EIA evaluated Bakken reserves at 690 and Eagle Ford reserves at 588 million tons. I don’t know… I don’t believe this. There has never been a case in the oil industry practice that after recovering just 25% of the recoverable reserves the oil production dropped by 33% in a year, like in Eagle Ford. So, I won’t take these estimations into consideration YET, I’ll get back to them later.
Table 2 shows that the development of the oil fields began 2 years later than that of the gas fields, but the production maximum was achieved sooner, in 4 years. This is the result of the difference in the economics. Oil has always been more expensive than gas, it is easier to transport and store, so, all other conditions being equal, drilling for oil is more profitable.
Bakken field contains two oil layers, composed predominantly of sandstones. Porous rocks hold oil better, so the production decline here is lower than in the Eagle Ford. Practice shows that the high productivity of the wells was mainly defined by the two factors: the formation's thickness and its natural fracturing. With these two factors available the initial production rate reached 500 t/d, and the annual production was as high as 25-45 thousand tons of oil, which covered the expenses. On the other hand, the increase of the frac stages over 10-12 and other technological parameters hardly affected the productivity.
This proves the sound truth: endless advancement of hydraulic fracturing is impossible. In tight thin beds wells produce dozens times less oil and it can’t be compensated by ANY super-technology. That is why the average initial production rate in Bakken field amounts to just 73 t/d, but not 300.
Eagle Ford field, on the contrary, contains fractured limestone and dolomites, which yield oil easier, in the productive layer. But the volume of the fractures is very little. So, both the initial production rates and their decline are higher here. The production decline by a third last year is a kind of anti-record in the oil industry practice. I, in any case, have never seen such examples before.
The Permian Basin formation is the last shale field with a growing production. There are as many as three oil layers, but their productivity varies a lot depending on the area (not to overload the material I am not showing well spacing maps, which are available in my previous work). This is an old oil province. Almost 40 million tons of oil from conventional beds is produced there annually, the pipeline system and the treatment facilities were built earlier. There is still room to look for productive areas. And they are being looked for: HALF of the American rigs drilling for oil (246) are working in the Permian basin.
Oil and gas have long ago been produced from Niobrara formation. Mature fields produce 140 thousand b/d here, but low-permeable (shale) beds – twice as much. Though the production rates are much lower and the reserves (according to the operational estimations) are 3-4 times less than those in the three main fields.
The four major shale formations combined produce 3.4 million barrels of oil per day, which is three quarters of all shale production or 39% of the total production in the US. Apart from them there are several smaller blocks, but the formations there are even more depleted. I’ll use Granit Wash field in Texas with the maximum production of 1.2 million tons a year as an example (pic.3). In 2015 the production dropped by 36.5%, last year by another 40.5%. Despite the fact that 10-11 drilling rigs are constantly working in the field.
Though let's get back to the recent events. After the drop of oil prices in February drilling was reducing for another 3 months and only in the summer, when the prices established at the level of over $40, the rig count started growing (pic.4).
During the half of the year it grew from 203 to 318, by 1.57 times in the large fields. But look – 97 of the new rigs (81%) started working in Permian basin. To fill up the canvas we should show the dynamics of the suspended wells number (pic. 5).
The chart shows that last year the number of suspended wells in Bakken field reduced by 17, in Niobrara – by 123, in Eagle Ford – by 283, but in Permian in INCREASED by 303 wells. In November 99 of the 312 drilled wells joined the idle well stock.
This means that the most perspective shale field doesn’t have enough highly profitable sites for all comers. Now we are witnessing a drilling rush, which will soon find the most productive zones and bring the Permian Basin field to the production maximum. Which will be followed by a rapid decline.
Some increase in the number of suspended wells in September-October could be seen in the other three fields (pic.5). But they are within the statistical error, so we won’t jump into conclusions.
The remaining recoverable reserves (530 mln tons of oil) with the current recovery rate (169 mln t/year) will be produced within three years. Even if we accept the clearly overestimated evaluation of the EIA for Bakken and Eagle Ford reserves this period will stretch up to 8 years. But in fact it won’t be possible to sustain the current production level, even though some of the wells will keep producing for another 10-20 years.
3. ON THE FUTURE PERSPECTIVES
Due to the efforts of enthusiastic expositors the shale fields look like limitless fields of, say, potatoes, in the public eye. Wherever you dig, you are guaranteed to find 10 pounds of the vegetable. It’s a pity that the companies tried too hard and dag out too much, oversupplying the market. Now the surplus of the potatoes is going to be eaten, the price is going to grow and everybody will vigorously grab the spades again.
In fact the analogy with Siberian moor would be more appropriate here:there are the hillocks and ridges red with ripe cranberries surrounded by a vast green marsh with a few berries on a square meter. Only interms of shale formations productive areas are tectonic disturbance zones. Look how wells stretch along these zones in Bakken field (pic.6). The largest of them is called Nesson Anticline.
I came across this phenomenon for the first time (frightful to think!) almost 40 years ago. In Severny Malgobek field in Ingushetia a well, drilled a kilometer away from a deep fault produced 400 t/d of pure oil after a massive acid frac. Three other wells located 2-3 km away from the fault had weak flows and were abandoned. And later in West Siberia, Komi, Povolzhye, India I saw for myself that in low-permeable beds the production rate is defined by their fracturing.
That is why I conventionally divide the reserves of shale oil in the US in three large groups. The first group contains thick layers with intensive fracturing, which provides for oil flow from around 0.5-1.5 km. In such zones the initial production rates reach hundreds tons a day. After the formation pressure declines the flow becomes dozens times lower, but it is stimulated by the gas separation in the formation. Such wells may produce 2-3 t/d for another 10-20 years with regular sucker-rod pumps.
The second group is described by limited fracturing, which spreads for just dozens and hundred meters. The initial production rates there usually amount to 50-100 t/d. In 4-5 years the production rate declines to 0.5-1 t/d and becomes noneconomic. The wells stay idle for a long time and are eventually abandoned.
The third group includes thin layers with very small fractures, which provide for almost no permeability. The initial production rate in such wells doesn’t exceed 50 t/d. Because of the formation pressure decline gas starts coming out in the formation, but in the very slim channels it doesn’t stimulate, but blocks the oil flow. These wells deplete within 1-2 years, and they are the ones, which make the biggest part of the suspended well stock.
The shale companies can’t allow an abrupt drop in production, since they won’t be able to account for the money already invested. Using the tiniest chance they will increase drilling. The coming rise in the oil prices will cause the second shale gale, but it will be a feeble semblance of the first one, because in 2-3 years’ time there won’t be any good sites for drilling left.
However, it is not necessary to have huge shale formations of dozens of thousands square kilometers to increase the production. Multistage hydraulic fracturing technologies are capable of bringing new life to hundreds of low-permeable layers in the well-known fields. In West Siberia, for example, they couldn’t enhance the recovery from the gas condensate wells in Achimov formation for 25 years, but now the objective is achieved by both multistage and large-scope hydraulic fracturing. Similar operations are extensively carried out in the USA, Canada, China and other oil producing regions. To get a good result only two factors are needed: a sufficient bed thickness (over 15 m) and the absence of underlying aquifer.
So, the perspective is not so much about certain fields as it is about the technologies, which would enable to involve low-permeable formations into the development. And here there is a great deal to do. Since the current oil recovery factors (5-6%) can in no way satisfy a thrifty owner; water flooding should be considered already, though it is yet unavailable.
1. The reserves of the largest shale gas fields in the US are enough to sustain the current level of production for 4-5 years, with the riseing as prices by 1.5-2 times this period will increase up to 7-8 years with a gradual decline in the production.
2. The proved reserves of shale oil in the four largest fields in the US are recovered by 59%.The increase of prices that happened, facilitated drilling in Permian Basin by 1.5 times, but it only slightly affected the other fields. Nevertheless, some increase in the shale oil production is possible this year due to drilling the remaining highly productive areas. Then the production in the USA will start declining slowly irrespective of increase in the prices.
3. As the most productive reserves get depleted the number of active rigs will have less and less effect on the recovery from shale fields. During the last 5 months in Permian Basin field from 18 to 32% of the drilled wells have not been completed, but suspended.
4. So, the oil exporters don’t need to worry about shale oil renaissance; new drilling is no longer capable of compensating for the depletion of the reserves under development.
5. Nevertheless, the hard-to-recover reserves are a good support for the oil industry; they are especially useful in old oil regions with existing industrial facilities and experienced workers. So, as they say, what ever happens happens for the best…:)))