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Alexander Khurshudov: Rumors about the US becoming the largest global oil producer prove to be greatly exaggerated

Alexander Khurshudov, expert Oil and Gas Information Agency
April 17, 2019/ 08:01

The news had been prepared carefully. A year ago, Voice of America announced that the United States could become the largest global oil producer. Soon there were reports that they had already overtaken Russia and Saudi Arabia. Finally, in September, the EIA made a statement: “The United States is now the largest oil producer in the world”. The news soon spread around the world.

The triumph turned out to be premature. Well, according to field production data, the US oil production is still exceeding indicators for Russia and Saudi Arabia, but updated values ​​ for December-January have recently been published. They turned out to be different.

  1. Last year results

Last year the United States produced 4,001 million barrels of oil, 40 million barrels less than Russia (Table 1). Why did this happen? Because PR people chose the best data for daily and monthly production, which are different. There was a period of hurricanes, when almost a quarter of wells in the Gulf of Mexico were idle. There were winter frosts in North Dakota, which made it difficult to operate wells. There was a hot summer in Texas, when light fractions of oil were lost because of excess evaporation in tanks.

Table 1

Besides, this is a very light oil. The average density of Russian Urals oil is 865.5 kg / m3, while the density of American WTI has decreased from 831 to 824 kg / m3 over the past two years. That is why it is cheaper than the Brent and Urals. If measured in tons, the Russian Federation produced 5.5% more than the United States and 7.3% more than Saudi Arabia.

It is interesting to estimate how much gas condensate there is in American oil. Russian oil contains 6-6.5%. Calculations from EIA data give 7.5-8% content for American oil. However, if we make an effort and add up oil of different density, it turns out that 20.3% of American oil (2.3 million barrels per day) have a density below 800 kg / m3. This is actually condensate slightly diluted with heavier fractions.

Nevertheless, the growth of American oil production by 2017 is unprecedented - 17.2%. Let's see what it is due to (Table 2).


Table 2


It turns out that production increased not only in famous shale formations, but also offshore and even in old fairly depleted fields. That's the kind of magic a price increase can do. From April to October the WTI price ranged within $ 66-71 and all the downhole pumps worked to their full capacity. While in November, after the price fell to $57, the growth ended; the cold January even brought a reduction by 90 thousand barrels per day. Now let's see how production has changed in large shale formations.

  1. Situation in shale basins

Fig.1 shows the change in production in shale basins.


Here the main character is the Permian Basin formation with an area of ​​220 thousand km2. Last year 493 rigs drilled for oil there, more than half the US oil rigs. Highly productive areas have been found in the northwestern part of the basin, New Mexico; this year production here increased by 71% (Fig. 2). Please note, the entire increase was due to super-light oil, and the production of pure condensate increased 2.9 times.

Fig. 2

Only three years ago the Permian Basin shale deposits were considered not too good. Production there amounted to 66 million barrels per year, proven reserves were 782 million barrels. Since then, they have grown 16 and 10.6 times. The main problem was low productivity. An average well initially produced 230-250 barrels per day, less than a half of the Bakken and Eagle Ford wells. At the same time, low oil price made production totally uneconomical.

The situation changed when they increased horizontal wellbore to 3 km and began to perform 25-30-staged hydraulic fracturing. Initial productivity doubled, to 470-500 barrels per day. In addition, oil price grew. Last year, the Permian Basin produced 1,058 million barrels of oil and condensate. The number of wells drilled there quickly reached 28.2 thousand, 4 thousand of which have not been completed yet.

Super-long horizontal wellbores have been praised a lot, but let’s look closely at their pros and cons. Fig.3 illustrates that.



The advantage is that drilling one super-long well instead of two short ones saves the cost of one vertical wellbore with a kick-off. However, such drilling is now done in 4-5 days and costs $ 1-1.5 million. Considering the total costs of a license, drilling and completion, which range within $6-9 million, the savings will be 17%.

The disadvantages are less noticeable, because they turn up during operation. It is much more difficult to operate a three-kilometer horizontal wellbore, therefore any complications cause a longer shut-down and bigger production losses. These include sand plugs, paraffin deposits and scaling, water and gas breakthrough. Fig. 3 demonstrates an example that when a water breakthrough occurs, a super-long well has to be shut down for workover, while one of two short wells continues to produce.

No wonder that the Permian basin wells’ production declines the fastest. In February the average of 486 completed new wells produced 606 bpd of oil, and the average of 23,614 old ones declined in production by 10.6 bpd. But let's go further.

By January this year the active rig count increased from 49 to 80 at the Eagle Ford field. However, production declined at first (see Fig. 1). By the summer of 2017 it reached its minimum (966 mbopd), and only then increased by 24% within 1.5 years. However, it is far from its 2015 maximum (1.6 mbopd). 12,157 wells are drilled within 9.2 thousand km2 oil-bearing formation here​​. Now a super-long wellbore sweeps approximately 1.8 km2, but in previous years well spacing was denser. On average, there is one well per 0.76 km2 in the Eagle Ford, which means that the field is almost completely drilled out.

Production in other fields is gradually increasing (Fig.1). Here, rig count has increased from 185 to 264 over the past two years, with production increasing from 0.866 to 1.394 million barrels per day (61%). However, the productivity of these deposits is significantly lower. While production is still increasing in the Niobrara area, a decline has begun in the Andarko basin.

There is more generally available information on the Bakken Formation than on the other ones (thanks to North Dakota State Administration), so let’s talk more about it. Two years ago I wrote that 91% of the all oil there is produced in four districts: McKenzie, Mountrail, Dann and Williams. Nothing has changed since then (Table 3).

Table 3

The same four districts covering the total area of ​​23.4 thousand km2 provide 94.6% of the state’s production. The remaining part of the field covering ​​44.56 thousand km2 accounts for 5.4% of oil production. Over the past two years, 2096 wells have been drilled there, the total well stock has reached 17,577, with 2,226 inactive wells.

In the four districts, there is a well per 1.74 km2 of reservoir, while in McKenzie, the most productive district, it is a well per 1.46 km2. Let me remind you that the current super-long wells take up ​​1.8 km2. There is no free land in McKenzie County, they are doing infill drilling in the area drilled out 8-10 years ago.

The wells’ production rate increased by 26% in 2 years’ time. No wonder, since they have been drilling super-long wells with initial production of 90-100 tons/day for three years. In the first few months, every such well compensates for a dozen weak and inactive ones. Though reservoirs deplete quickly, a pressure drop causes an increase in gas-oil ratio. In McKenzie County, it has already exceeded 500 m3/t, which is 3.5 times over the initial values.

Fig.4 shows production dynamics.


One can see that McKenzie provides 40% of current production, and it continues to grow, but Mountrail, 2012 leader, has failed to reach its previous maximum. In low productive areas production is declining. In addition, the number of active drilling rigs in the basin has increased from 33 to 56 in the last 2 years, which is but a trifle for such a huge area. Seven years ago, more than 200 rigs worked at Bakken.

Speaking of this growth one may think that it is nothing but a dead cat bounce…Though it is not true. The cat will be sick for quite a long time and it won’t depart for a few more decades. Let me explain the reason.

A huge well stock, tens of thousands of wells are drilled in shale deposits. They get depleted, watercut, switch from oil to gas, nevertheless, they are possible to work with. One can reduce the influx of water or gas using special chemicals, reperforate unproductive reservoir intervals, sidetrack into poorly swept areas. There are also other less common tricks.

I have been watching two wells in the Bakken formation (Fig. 5) for three years. The well BILL 14-23 1H has been depleted twice, but both times well interventions performed in it (shown with red arrows) brought it back to the production stock.

Fig. 5

This well is a supporter, it has produced 300 thousand barrels of oil in 7 years, it has paid back in spades. The reservoir it penetrates is already extensively depleted, gas-oil ratio has increased to 900 m3/t (Fig. 6), and oil production rate has dropped to 6.5 tons / day. Though it will produce for a few more years; under the circumstances it is economic to produce as little as half a ton of oil per day.


Alas, the nearby well BILL 14-23 5 TFH (see fig. 5) is several times less productive. After three unsuccessful well interventions, it produces less than 5 tons of oil per day and will never pay back. Though, it will work for a few more years.

There is a lot of oil in the reservoir. The most modest estimates say that Bakken has at least 22 billion tons of original oil in place. Although the EIA assumes oil recovery factor to be 5%, while in fact 1.8% has been produced so far. A huge amount of oil remains in the reservoir, it may be extracted by driblets for hundreds of years, but so far the economics is not favorable. Now let’s move on to reserves balance.

  1. Proved reserves

Fig. 7 shows the dynamics of changes in the US shale proven oil reserves


Over the past 5 years, proved reserves have doubled, but not a single new field has been discovered. All the changes are due to recalculation. The United States territory is geologically studied far and wide; they knew about this oil decades ago. Then it was just uneconomic to produce.

It became economic for two reasons: the increase in oil price and in horizontal wellbore length. After the decline in prices in 2015, proved reserves decreased. Now they are growing along with prices. Table 4 shows the EIA data with an adjustment for last year's production. Do you, readers, think we can trust these numbers?

Table 4


I think they are overestimated by 30-40%. I will explain the reasons.

There is no serious experience in low-permeable formations development in the world. What is available for us is mainly oil located in fractures. It is quite realistic to assess fracture zones by remote methods, but core is needed to estimate formation properties (fracture porosity, opening, etc.). Although, even core does not guarantee that the fractures will have the same properties 100-200 m away.

Moreover, no one has closely analyzed shale formations development. It is, of course, extremely complicated – every formation is developed by hundreds of operators, each accelerating production trying to get ahead of their neighbor. The EIA processes statistics coming to it, tries to divide deposits by productivity into typical blocks and predicts recovery factor based on this. However, if you take a look at pic. 5, there are two wells located nearby, and their cumulative production differs EIGHT TIMES. Is the value of such forecasts high enough?

I have a problem with the reserves table. Since proved reserves at the Eagle Ford amount to as much as 612 million tons, why are 69 drilling rigs working there now, and not 250, like 7 years ago? There is no room left? Well, the Bakken formation in North Dakota is 7.4 times larger, current reserves are estimated at 693 million tons, and still 61 rigs are operating. Why do all the rigs crowd around the Permian, although each of them produces 2.4 times less oil than those in the Bakken?

Yes, my doubts about the optimistic assessment of shale oil reserves are justified. I think, we’ll have a chance to see it within the next three years.

  1. Summary

This year, oil prices broke the down trend. The Brent price has increased to $ 71.52 (by 37%), WTI - to $ 63.8 (by 43%). The global financial crisis has not happened, it got postponed indefinitely. The OPEC has reduced production much more than promised, by 2.276 million bpd over the past 4 months; in March they were producing 30 million barrels per day.

Circumstances have changed a lot, and I have to adjust my January price forecast. By the end of the year, the Brent may exceed $80, WTI may grow to $ 72-75. With such prices, the production of shale oil should be profitable, all economic restrictions will be removed. Then it will become clear whether the reserves are real or virtual. I think the United States will still break new records and become the world's largest oil producer, but this leadership won’t last long.

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