Shale Oil Fiasco

[James Gautreau + 86]

Fracking has been used on about 1 million wells bored since 2007, and oil and gas companies now fracture as many as 35,000 wells each year, according to FracFocus, the national fracking chemical registry.

 

Rest of article:

https://www.reuters.com/article/us-energy-refracking-insight/refracking-brings-vintage-oil-and-gas-wells-to-life-idUSKBN0GK0CC20140820

 

So refracking is already in the mix no? I can't find how much oil is produced after the refrack compared to the first time. Do you know?

[James Gautreau + 86]

17 minutes ago, PE Scott said:

That article seems more or less accurate from my perspective. The one thing that's impossible to account for just yet is the impact recompletes will have. I have heard very promising results from a number of smaller operators who have been taking advantage of cheap service company pricing to do work overs and recompletes. 

I think, perhaps, we've underestimated the life of some of the unconventional wells as new completion techniques make recompletes more attractive. In that scenario, I could perhaps see better overall recovery from existing wells. 

 

Here is another. 

https://oilprice.com/Latest-Energy-News/World-News/Refracking-Extracts-200000-250000-Additional-Barrels-In-Bakken.html

 

So it takes EUR up 200,000-250,000 so a nice bump. But I've read it only works well in the Bakken. 

[jjj + 26]

27 minutes ago, James Gautreau said:

I hear you. But AC Rigs have been around since at least 2013. I'm sure the diesel only rigs are mostly gone by now. I interviewed with a company who was developing a new rig a little while back, never heard back. Walkable rigs where all the key parameters are known with certainty. Let me ask you this. A rig gets put on a pad, drills down and then laterals of a mile or two east. Then it turns and drills southeast for a mile or two. Then south. I have read a single pad is 100 acres. Now is that one well or 8 wells. And how much would that 8 direction, single hole down well, cost?

I built my first A/C rig in 2012. But diesel rigs were still a major factor running in the Permian until 2015. Those rigs and the SCR rigs were stacked in or before 2015 but are just now being scrapped. I am unaware of any post 2012 A/C rigs being scrapped that wasn't one of the few that were so messed up from the factory to be considered junk. Even the few I messed up in 2012 were upgraded in 2016 and now work fine.

I do know of 2 rigs that were older SCR rigs that were upgraded, they spent over $2 million on each and neither has ever been under contract. Major upgrades were a VFD house, A/C Mud pumps and Drawworks, and a Columbia walking system. But it still takes 5 days to move it and it won't take the latest high torque top drives. So no takers eventually they will be scrapped.

No surprise on the deal you mentioned going dead. Almost nobody is building new rigs just too many were built between 2012 and 2015. I know Patterson had a substructure for a new rig being built in Houston and that is the only one I know of right now. Our biggest competitor back in the day Applied Machinery Corp closed their door earlier this year. 

On your second question I can not help you I built them to specifications what they cost to operate and even to a certain degree anything down-hole is not my expertise. 

Jay 

[James Gautreau + 86]

 

First place I found that predicted 2020 as the peak, albeit at a much lower number than shale achieved. I think it is up to 8.8, but that only means the fall will be harder and faster.

[James Gautreau + 86]

I think refracking is already in the mix. This could explain the huge decline rates of 2018, along with the Tier 1 acerage exhaustion. One thing that makes me suspicious is there is no accounting of it that I could find like the DUC's. That means it could already be a big part of production. 

[PE Scott + 563]

I'm not sure how many are done right now, honestly. I have only been a participant in a handful of them myself. Basically just word on the street, but I've heard some smaller operators say they were going to focus more resources on recompletes in upcoming years because the economics looked promising.

[Jabbar + 465]

1 hour ago, James Gautreau said:

Here is another. 

https://oilprice.com/Latest-Energy-News/World-News/Refracking-Extracts-200000-250000-Additional-Barrels-In-Bakken.html

 

So it takes EUR up 200,000-250,000 so a nice bump. But I've read it only works well in the Bakken. 

Mostly Bakken and Eagleford on early vintage wells pre 2014

[James Gautreau + 86]

9 minutes ago, Jabbar said:

Mostly Bakken and Eagleford on early vintage wells pre 2014

Yeah that's right. Those early wells were under-stimulated and were good candidates. I don't think it will amount to much if it doesn't apply to the Permian. 

[Jabbar + 465]

2 hours ago, Coffeeguyzz said:

Fascinating thread.

Lottsa familiar 'faces' posting.

Mr. Buckland, however you may characterize 'new/transformative' technologies in this unconventional realm, it is simply incontrovertible that reduced costs are aiding operators in their ongoing struggles to achieve viability going forward.

Simply looking at Bakken D&C costs now at the ~$5 million range should indicate several follow on consequences beneficial to the upstream boys. (Marathon just brought online 4 wells with average D&C of $4 1/2 million per. The Niobrara operators have been pegging costs at the ~$3/$4 million dollar range ... greatly compensating for relatively low EURs).

Regarding higher primary recovery rates, skeptics may question both Conoco and Continental's claims of ~20%, but ongoing processes - some described in this thread - should validate that this is actually happening.

(BTW, Harold just announced he is stepping aside. A true giant in this industry).

 

The single approach of Extreme Limited Entry Perforating, whereby an ever expanding 'pressure bubble' in the 1,500/2,000 psi range is but one method in this unending process of innovation.

Controlling the frac geometry with real time monitoring, pump pressures/volumes, diverters - both far field and near wellbore ... on and on. 

 

Mr. Scott, your input  is especially informative and I thank you for your contributions.

Suggest you check out the NETL project in which  Schlumberger and Chevron are participating focusing on how  natgas - injected as a foam - might be used as a frac'ing medium.

As Hess has just announced an EOR project using NG in foam form, this approach may prove to be impactful. High clay content formations such as Bazhenov could be particularly affected by a successful implementation.

 

A macro view of the energy field - particularly hydrocarbons - shows a distinct advantage for the continual shift towards natgas as a fuel over oil.

As of this posting, $13.51 buys an equivalent amount of heat energy in gaseous form as that found in a barrel of earl.

The blinding pace of hardware and process innovation in the LNG realm has brought us to the point where US LNG is now cheaper than piped gas from Malaysia, Indonesia, Russia, Israel (Leviathon), and Algeria to Europe, Turkey, Singapore and Cyprus. The HH price indexing plays a huge role in this.

New world is upon us, folks.

Long live Cowboyistan.

Wasn't the term  "Cowboyistan" coined by Harold Hamm ? 

Harold stepped down as CEO of Continental today after an accomplished reign for 30 years.

He remains as Chairman of the Board

Edited December 12, 2019 by Jabbar

[PE Scott + 563]

43 minutes ago, James Gautreau said:

Yeah that's right. Those early wells were under-stimulated and were good candidates. I don't think it will amount to much if it doesn't apply to the Permian. 

I was trying to find a different paper I had read on this subject, but I cant seem to locate it.

https://www.researchgate.net/publication/239949908_Reservoir_stress_path_characterization_and_its_implications_for_fluid-flow_production_simulation

This paper is pretty similar and explains a lot of the same stuff. Specifically, it talks about how changes in pores pressure result in different stress paths, ie. the fractures should propagate in different directions if recompleted. Depending on the type of formation, this could be very beneficial. I cant comment on specific reservoirs in the Permian, but the physics of it looks promising in the right circumstances.

[Boat + 1,315]

Thanks coffeeguyzz for your input. From old days at Peakoil.com I learned a lot about oil in general and your experience. Perhaps you can comment on this.

From reading I gather 40 to 60% of oil is still trapped after even fracking. With that treasure sitting there waiting for a solution I would guess many smart experienced minds are working feverishly to crack that safe. 

 

[markslawson + 1,042]

On 12/11/2019 at 1:35 PM, Douglas Buckland said:

So, you might be able to utilize mothballed rigs which have been stacked, not a problem....now try to crew them up with people that know how to drill or have any idea of well control. Worse than that, try to find, and attract back to the industry, experienced drilling managers, drilling engineers, superintendents, supervisors, geologists, fluid engineers, etc....

I now leave it with YOU...

Douglas - again you have completely missed the point. These cycles have happened several times. You need to sit down and think what happened at each cycle? How did the industry bounce back. There is nothing to suggest this cycle is in any way different, or at least you have to show that it is in some way different. Of course its dreadful that these people lose their jobs but its all happened before and you will find that the companies involved have some way of recruiting the skill. I would urge you to adopt a balanced view of these matters, and take on board what I said. That's the end of comments on this issue for me.  

Edited December 13, 2019 by markslawson
correcting a typo

[Coffeeguyzz + 454]

Boat

Hope you are doing well.

As succinctly as I may be able to answer your question, the currently accepted rate of primary recovery in the shales is 8 to 12 per cent.

Different operators/formations/skill (luck?) plus a whole bunch of other factors loom large in these matters.

For context, the early Montana/North Dakota Bakken operators were getting ~3% OOIP and thought that it was great.

Prior to that, only the smaller natgas molecules were deemed recoverable so getting any oil out was considered an achievement.

Esteemed geologist Kathy Nesset (she started mud logging in North Dakota in 1979) has stated that 12 to 15 percent is now more often achieved across a wider swath of acreage.

I would refer you to the recent (August, 2019) presentation from Jim Sorensen of the UND EERC titled "Bakken Rich Gas EOR".

On pages #22/23, there is a profoundly important factoid that looms large over this entire decline rate/recovery potential/EOR stuff that several fuzzy heads have been surmising for years ... namely asphaltene precipitation and the follow on blockage of these tiny, tiny pore throats and induced pathways.

When the C 12 through C 24 molecules show a MUCH higher mobility rate with propane versus produced gas, one may conclude that these fat ass molecules just ain't makin' it out the door as formation pressure draws down.

Long winded reply, Boat, to attempt to highlight just how much is yet to be learned.

Edited December 13, 2019 by Coffeeguyzz

[Douglas Buckland + 6,308]

6 hours ago, Boat said:

Let me tell you a story about tech. A buddy worked for Boeing running wire. A typical section of the plane would take 7 hrs to poke all the wire through hundreds of grommets. He suggested a larger size hole because the wires were so tough to pull through the hole. After the engineers okayed the bigger hole labor time per “harness” was cut to 3 hrs. He was given a $5,000 bonus. Most tech is the accumulation of thousands of small improvements in thousands of areas. Most improvements will never be patented or recognized. This is tech and the way the world has worked since humans came along.

Even big ideas and new products come on the backs of old and existing ideas. 

A larger sized hole to pull the wire through makes absolutely no sense if the hole in the grommet (the sealing mechanism through the bulkhead, etc...) remains the same diameter. The grommets are sized for a specific wire diameter and the necessary sealing effect. Making larger holes for the same sized grommet will NOT make pulling the wire any easier.

If what you meant was a larger sized hole through the grommet, you would lose sealing efficiency.

Something is not right with this scenario.

[Boat + 1,315]

1 hour ago, Douglas Buckland said:

A larger sized hole to pull the wire through makes absolutely no sense if the hole in the grommet (the sealing mechanism through the bulkhead, etc...) remains the same diameter. The grommets are sized for a specific wire diameter and the necessary sealing effect. Making larger holes for the same sized grommet will NOT make pulling the wire any easier.

If what you meant was a larger sized hole through the grommet, you would lose sealing efficiency.

Something is not right with this scenario.

Your nuts young man. Lol 

[Boat + 1,315]

8 hours ago, PE Scott said:

If I'm being honest with myself, I know we're only a couple innovations away from a computer being able to do the majority of my job. I think the same could be said for many other jobs as well. Hard to say when and if those innovations will occur in my lifetime though.

This is not related to oil but a flat tax would eliminate over a million accountant jobs overnight. A lot of people to push digital money.  Machine algorithms are becoming important to cut inefficiency/jobs. But has yet still to get to scale. We’re just kinda warming up to the idea. But if the US really wanted to compete with the world getting rid of these “welfare jobs” would be huge.
 

Edited December 13, 2019 by Boat

[Ian Austin + 131]

On 12/5/2019 at 6:22 AM, Tom Kirkman said:

Good observation.

Niggling point, DUCs will likely only get reduced in number, but will not go away completely within the forseeable future.

Given half the Pressure Pumpers are struggling with profitability, some shelving equipment etc, I if there’s a bit of a problem brewing. 

I can see it now (based on experience):

Service Industry: were busier than ever, but don’t make a penny, we’re “right sizing” our fleet and laying off (pretty much all majors have...)

Producers: we need more equipment. Gotta clear the backlog. Our wells are shittier than ever so we need a lot more of them 

Service Industry: Ok. We’ve taken an 80% hair cut since 2015, so we’ll need 30% above and beyond today’s rates to start up again

Producers: ..........

Service Industry: So, should we start assessing useless equipment and que up the Hiring Campaigns?

Producers: ..............

[Ward Smith + 6,615]

2 minutes ago, Boat said:

Six Sigma is a process to find root problems that nobody wants to here for example.

Yeh lik spling erers 

[Boat + 1,315]

US educated and old. Blame Republicans for to big a class size. 

[Jabbar + 465]

9 hours ago, James Gautreau said:

So if we are entirely relying on shale, and the fact Exxon and Chevron and Occidental are there, tells me they don't have any better sites, we may be SOL. They turned down Brazil. Flat out, and it's probably the best offshore site in the world. What makes oil riches is that daily production over decades. I think I read somewhere Al Ghawar is a $5 trillion dollar asset, the largest in world history and it's still going. By the end it could nearly pay off our national debt. What makes oil poor men is chicas champagne flash they don't last. That's shale. Sure production is all front loaded and that's the problem. It's for months now, not even years. 

 

 

 

Most of these players have been in Permian for 60 years.  West Texas was THE U.S. oil industry for years.  Many have the acreage rights from then and now don't have to buy anything or pay little or no royalties.

Exxon had some property in Permian , but did pay Bass Brothers $6 Billion for their land a few years ago. EXXON has piece of pre salt from auction years ago.  Everyone skipped the last auction (accept China) because of ridiculous terms.  Brazil is going back to redo the terms.  The next suction should do better.

Few of the majors have commissioned 3D mapping of offshore Argentina. Could be huge. All the majors are in on Argentina's Shale development.  

Brazil best ? Maybe.  EXXON found 6 Billion barrels off Guyana with great terms. First production 120,000/day going to 750,000/day by 2025. They just bought 7 million acres off of West Africa , Namibia (next to Angola) . Some say as good as Brazil pre salt. 

Chevron has some great leases in GOM . They just authorized a first phase project that will cost $5.7 Billion. 

Chevron writing off $11 Billion of gas/long business.  Due to high LNG shipping costs U.S. can't compete with Russian gas from pipeline.  They are looking to unload some of gas assets. 

Exxon paid $42 Billion for XTO Shale gas assets and only wrote off $3 Billion.  

Investors over obsess about U.S. shale to a fault.  Probably because OPEC blames all their problems on U.S. shale.

U.S. shale not months left but decades. 

U.S. shale not OPECs biggest problem.  South America, Africa and OPEC members themselves are all increasing production.  

Too much oil 

 

 

Edited December 13, 2019 by Jabbar

[Douglas Buckland + 6,308]

2 hours ago, Boat said:

Your nuts young man. Lol 

What part of my reply do you actually disagree with?

PS: I passed ‘young’ decades ago.

[Zhong Lu + 845]

If you think shale is doing poorly, look at natural gas. It's like watching an abused kid get abused even more.  

[PE Scott + 563]

I went back to read through some earlier posts and noticed a few trends in discussion I wanted to highlight from a field perspective.

When looking at well production data and EUR, its important to correlate some other information from the wells that's hard to see in publicly available data. I see where its tempting to think that if production is falling off faster it must be because the new wells are in "tier 2" acreage. Sometimes this may be the case, often I suspect completion techniques are responsible for a faster decline. 

As an example, water has become increasingly more expensive/scarce in the Permian. As a result, consultants in the field were often given blanket authority to cut water volume by increasing proppant loadings far earlier in a treatment. While this saved money and they managed to put the designed proppant volume away without screening out, the fracture geometry isn't what engineers intended. There still were great near-welbore fractures generated and initial oil production on these wells was high. However, as @Douglas Buckland pointed out early on, communication more than short distance beyond the fracture is nearly impossible because of the low permeability. So, effectively you're communicating with a much smaller area of the reservoir because your fractures weren't aloud to propagate all in the name of saving a couple dollars on water.  More recently, I've seen operators be more specific about following design and trying to generate a more specific fracture geometry. My opinion is the difference will dictate EUR but won't be noticed right away. 

Another thing, I guess you can call this technology, is the advent and popularity of slickwater should result in better overall production results. HVFR has only become popular over tha past couple years and offers many of the advantages of gel without the long lasting skin effects. That should help provide more consistent results than sensitive guar systems moving forward.

Another thing, I don't know exactly when the shift occurred, but at some point the industry all but abandoned sliding sleeves in favor of plug and perf completions. I can't overstate the importance of this evolution and importance of the distinction between the two completion types. Sliding sleeves would rarely generate the kind of fracture complexity or targeted results we're able to generate with P&P completions. 

Beyond that, I think @wrs touched on another subject that's often overlooked: water disposal. It's becoming increasingly difficult to dispose of water. I'm not sure about TX, but in NM there is a serious backlog in UIC permits. There are concerns with how the water is disposed of and specifically concerns for induced seismicity like we saw in OK. In any event, from a design and production standpoint, more attention has to be focused on reducing water cut. I have already seen a great many changes in frac design to address this issue. Overall, I think this will incentivize more attention to fracture geometry and more targeted production. We'll see how it plays out.

 

[James Gautreau + 86]

The last time oil went ballistic there was a similar chatter on the news. There's a glut of oil. Oil should be half the price. There's no way oil is going any higher. Oil price collapse imminent.  It's exactly what's happening now. Granted the last couple of month have been good but to think you're going to add 1.2 mbpd in the last quarter is nuts, and yet EIA or IEA is maintaining 13.6 mbpd by end of year. The next 6 months will tell the tale, is shale oil over? 

[BByrd 0]

On 12/5/2019 at 9:29 PM, Douglas Buckland said:

People do not seem to realize that the root cause of the production problems associated with shale oil is the extremely low permeability or the ability for the rock to flow. There is only so much that you can do to mitigate this issue.

Let’s take a simplistic historical view. First a well is drilled vertically through a tight shale formation. This yields a certain surface area for hydrocarbons to enter the wellbore, which in turn gives a certain production rate for that surface area and permeability. The rate is uneconomical. How do we increase the permeability of the reservoir rock matrix? We can’t, so we must adjust the surface area. We now drill a lateral through the reservoir. Surface area of the wellbore increases and production goes up - for awhile. The near wellbore oil is recovered ‘easily’, but as the oil further from the wellbore is being recovered, the tortuous path between the shale grains becomes longer, friction becomes greater and it becomes more difficult for the oil to reach the wellbore. Eventually the production rate becomes uneconomical. We need even more surface area, so we hydraulically fracture the formation. Once again, more surface area yields higher production - until it doesn’t for exactly the same reasons described above. At some point the money runs out and you can neither increase the length of the laterals OR increase the number of stages in the frac program.

Okay, let’s just drill and frac a multitude of wells in the same area. This will yield a huge increase in the wellbore surface area (remember, you can’t really change the permeability of the actual reservoir rock) and production should skyrocket, and it does, right up to the point that it doesn’t and the parent/sibling well issue raises it’s ugly head.

At the end of the day, the shale oil boom will bust simply because you can not alter the deep reservoir permeability AND you’ve run out of money trying to do so.

That’s it in a nutshell.

Over to you Jabbar...

We were visiting last week and one of our older crowd commented it’s just drilling 30 or 40 vertical Sprayberry wells in the same wellbore for 8 mil