Shale Industry Suffering From Unexpected Operational Problems

[IsailedawayfromFR]

Despite rosy forecasts for U.S. crude output this year and next—the EIA sees production hitting almost 10 mbd in 2018—there are some warning signs beginning to emerge in the shale patch, even from what is the hottest and most prized shale basin of all—the Permian Basin. The industry may struggle to ratchet up production as rapidly as many analysts forecast due to a number of unforeseen problems, including sharper-than-expected decline rates.

First, there are bottlenecks for oilfield services, which could lead to a hike in production costs. Second, some signs suggest that the ever-increasing productivity gains for the Permian are starting to stagnate. But perhaps most worrying of all is the potential acceleration of decline rates at some shale wells, an ominous sign that the drilling bonanza in West Texas should not be taken for granted.

Production problems and decline rates

Shale wells typically see their production levels decline rapidly after an initial burst of output. Unlike a conventional oil field, which usually enjoys relatively stable production for years, output from a single shale well can fall off drastically within months. More shale wells need to be drilled just to keep production flat.

In the Permian, the rate of decline has accelerated recently. The decline from legacy wells, which are already in production, has grown dramatically in 2017. In September, according to the EIA, the Permian will see production from legacy wells fall by 158,000 barrels per day (b/d) month-on-month. That means that the shale industry will need to add at least as much new supply just to hold steady. That decline rate is 40 percent larger than a year earlier. Across the top shale basins in the U.S.—the Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian and Utica—the decline of oil output from legacy wells will have jumped by about 25 percent from September 2016 to around 400,000 b/d for the same month this year, according to the EIA.
http://energyfuse.org/shale-industry-suffers-unexpected-operational-problems/

This bears watching.

I'll also point out that, contrary to what article infers, rising GORs is not an operational problem.  It is instead symptomatic of reservoir performance.  In this case, it is a negative as expanding gas in the formation is what contributes most of the energy to propel liquids through the formation and thus into the wellbore to be produced.

I have been leery of the geology of the Permian to provide the continued production growth most estimates have assumed.

[Smokin Joe]

This bears watching.

I'll also point out that, contrary to what article infers, rising GORs is not an operational problem.  It is instead symptomatic of reservoir performance.  In this case, it is a negative as expanding gas in the formation is what contributes most of the energy to propel liquids through the formation and thus into the wellbore to be produced.

I have been leery of the geology of the Permian to provide the continued production growth most estimates have assumed.

Interesting. Thanks. This could impact this (Williston Basin) as well, but through renewed activity if those drilling the Permian lose interest. It might just mean the Permian isn't quite so figured out yet..

[IsailedawayfromFR]

Interesting. Thanks. This could impact this (Williston Basin) as well, but through renewed activity if those drilling the Permian lose interest. It might just mean the Permian isn't quite so figured out yet..

The Permian geos I trust tell me few continuous layers exist, unlike the Middle Bakken.

Horizontal encounter multiple, disconnected layers instead.

Not a great recipe for success. Especially in fraccing ability.

There is nothing like the Bakken on the planet found yet.  Predictability means something.

[Smokin Joe]

The Permian geos I trust tell me few continuous layers exist, unlike the Middle Bakken.

Horizontal encounter multiple, disconnected layers instead.

Not a great recipe for success. Especially in fraccing ability.

There is nothing like the Bakken on the planet found yet.  Predictability means something.

I may know of one other, more toward NGLs and Gas. I need to do some more digging into who has it.

[IsailedawayfromFR]

I may know of one other, more toward NGLs and Gas. I need to do some more digging into who has it.

The Eagleford has lots of brittle rock, but is mostly condensate and ngl too.

Only the Bakken has unmatched hi Q oil, overpressured, fractured naturally not overcooked  in world-class source beds and can flow oil at low gors. Another secret is you can stay in target zone within a couple of feet for 2-3 miles. Unheard of.

It is indeed unique.  And I resourced all north American and tons of international shales.

Just wish it was 200' thick.

[Smokin Joe]

The Eagleford has lots of brittle rock, but is mostly condensate and ngl too.

Only the Bakken has unmatched hi Q oil, overpressured, fractured naturally not overcooked  in world-class source beds and can flow oil at low gors. Another secret is you can stay in target zone within a couple of feet for 2-3 miles. Unheard of.

It is indeed unique.  And I resourced all north American and tons of international shales.

Just wish it was 200' thick.

I have done wellsite geology on well over 100 Bakken wells, so I know it better than many, if not most. It's a great formation in that sense. Recall, though, it was considered non-producible in all but the most unusual circumstances in vertical wells (I worked one of those in 1980, found quite by accident).

There is at least one more formation not generally recognized with such potential. I worked a well which drilled through that, too.

[IsailedawayfromFR]

I have done wellsite geology on well over 100 Bakken wells, so I know it better than many, if not most. It's a great formation in that sense. Recall, though, it was considered non-producible in all but the most unusual circumstances in vertical wells (I worked one of those in 1980, found quite by accident).

There is at least one more formation not generally recognized with such potential. I worked a well which drilled through that, too.

I do hope it is sandwiched between two source rocks like the MB is.  Otherwise, it will never get the overpressure and natural fraccing.

[Smokin Joe]

I do hope it is sandwiched between two source rocks like the MB is.  Otherwise, it will never get the overpressure and natural fraccing.

The overpressure is there, but contained by a retrograde condensate in a tight sand. No one, to my knowledge has tried to do laterals in it or frac them.

I saw it in a well near a wrench fault, and it darned near got away from us. The problem is that we could not get the folks in the office to believe that it was there and the real deal. It was not the known target, and had been drilled through without anyone taking a kick in the area (but not proximal to the fault). It took 13.8 mud to kill it, 13.4 to contain it, considered way overpressured for the area.

[IsailedawayfromFR]

The overpressure is there, but contained by a retrograde condensate in a tight sand. No one, to my knowledge has tried to do laterals in it or frac them.

I saw it in a well near a wrench fault, and it darned near got away from us. The problem is that we could not get the folks in the office to believe that it was there and the real deal. It was not the known target, and had been drilled through without anyone taking a kick in the area (but not proximal to the fault). It took 13.8 mud to kill it, 13.4 to contain it, considered way overpressured for the area.

hope the tight sand is brittle.  Condensate not as good as oil, but they do flow easy enough through tite pores.

[IsailedawayfromFR]

The overpressure is there, but contained by a retrograde condensate in a tight sand. No one, to my knowledge has tried to do laterals in it or frac them.

I saw it in a well near a wrench fault, and it darned near got away from us. The problem is that we could not get the folks in the office to believe that it was there and the real deal. It was not the known target, and had been drilled through without anyone taking a kick in the area (but not proximal to the fault). It took 13.8 mud to kill it, 13.4 to contain it, considered way overpressured for the area.

think moving through maturity window caused overpressure?

[Smokin Joe]

think moving through maturity window caused overpressure?

More likely updip migration.

[IsailedawayfromFR]

More likely updip migration.

That is less significant than expulsion from adjoining source beds such as in the Bakken.

[Smokin Joe]

That is less significant than expulsion from adjoining source beds such as in the Bakken.

Oh, it's bound by black shales, just not as pretty as the Bakken.

[IsailedawayfromFR]

Oh, it's bound by black shales, just not as pretty as the Bakken.

And that has been my point all along.  Although being a sand, one should expect more porosity than a carbonate, which is good.

[Smokin Joe]

And that has been my point all along.  Although being a sand, one should expect more porosity than a carbonate, which is good.

I think carbonate porosity is a lot less predictable than people think. I have been on rigs that drilled into cave (paleo Karst) and fractures that would drink every drop you pumped downhole and 'eat' the cuttings, too. The petrofabrics tend to be defined by biological debris and depositional environment as much as dolomitization (which is dependent to some degree on primary porosity). Lovely sucrosic dolomite is not as common as people think and the permeabilities tend to be anisotropic, even without fractures. One of the earlier NUMAR logs I saw (about '92) couldn't get a repeat section--tool centralization was on 120 degree centralizers, the hole was at 45 degrees, and the fossils in the wall were not reading out the same because the tool was riding a little different on each pass.

[IsailedawayfromFR]

I think carbonate porosity is a lot less predictable than people think. I have been on rigs that drilled into cave (paleo Karst) and fractures that would drink every drop you pumped downhole and 'eat' the cuttings, too. The petrofabrics tend to be defined by biological debris and depositional environment as much as dolomitization (which is dependent to some degree on primary porosity). Lovely sucrosic dolomite is not as common as people think and the permeabilities tend to be anisotropic, even without fractures. One of the earlier NUMAR logs I saw (about '92) couldn't get a repeat section--tool centralization was on 120 degree centralizers, the hole was at 45 degrees, and the fossils in the wall were not reading out the same because the tool was riding a little different on each pass.

I think the really outstanding porosity of carbonates is by microfracturing, not endemic matrix porosity.  If you can find it, you got it made; however, it is that predictability you mentioned, just tough.

I was leading a well we drilled into the Austin Chalk in the early 90s.  Just when we were making the turn at 8000',  the bit dropped and we lost all circulation.  After fighting it for 8 days and 18,000 bo produced, we called it quits and decided we found what we were looking for with a near vertical well.

It pays to be lucky sometimes.

[Smokin Joe]

I think the really outstanding porosity of carbonates is by microfracturing, not endemic matrix porosity.  If you can find it, you got it made; however, it is that predictability you mentioned, just tough.

I was leading a well we drilled into the Austin Chalk in the early 90s.  Just when we were making the turn at 8000',  the bit dropped and we lost all circulation.  After fighting it for 8 days and 18,000 bo produced, we called it quits and decided we found what we were looking for with a near vertical well.

It pays to be lucky sometimes.

I was on a well in Nevada, drilled into paleokarst near the top of the paleozoics. 9 ft. of drop, the hole eventually packed off, drilled another 90 ft. hit another cave. Finally got them to DST while we were building mud volume (again)--clear water.  Another valley in the same state, also hit cave, also hit clear water (200 ppm Chlorides--looked like oil on the resistivity log). The valley was parched desert with stringy-assed mustangs roaming around, but the BLM wouldn't let the company produce the water. Said the permit was for oil, so plug it or produce oil...P&A.  There are fractures on the Nesson Anticline that will drink everything you pour in them, cuttings gave just enough back pressure to get surveys, but never made it to surface from the lateral. You don't know until you get there. I'll grant those smaller fractures likely do most of the heavy lifting, but the big voids are an eye-opener as to just how little we know about what is going on down there.