Shale Oil Fiasco

[James Gautreau + 86]

7 minutes ago, PE Scott said:

Can I chime in as "Guy C" - pro frac but also pro reality?

I agree with Doug in the sense that I haven't seen any technology that substantially and consistently improved the EUR in wells when normalized for length, etc. As technology goes, please correct me if I'm wrong @Douglas Buckland, I think he's trying to illustrate that it hasnt changed the physics or overall recoverable oil on an individual well. Look at a technology meant to do this, like MicroScout from Halliburton, and find something that's actually made a big difference. I cant name anything and I'm a completion engineer......maybe I'm just bad at my job. As far as microscout goes.....it was 300 mesh sand meant to prop micro fractures and increase EUR by some significant percentage as a result of greater propped frac length. Most recently, I found it works better as a diverter if dropped in high concentration.......if you understand what I'm talking about....you'll know why this is not intended. 

However, theres more to making these wells economically viable than EUR. The biggest focus now, in my opinion, isn't trying to recover a greater percentage of oil from each well but rather trying to cut the completion cost wherever they can. I have seen stage cost drop from $80k to around $20k. The stages are nearly the same length and with the same amount or more proppant, but the chemicals and fluid volumes have dropped dramatically. The chemicals being used, like HVFR, are a fraction of the cost of running guar based gels. Every single person and piece of equipment on the surface is being optimized for efficiency. Average time between wells on a zipper is less than 15 minutes when things are running smoothly. It's not uncommon to complete 12 or more stages in 24 hours these days. That's lightning fast for plug and perf operations. That's where the technology has benefited the shale field though. It's not about higher production, it's about lower completion cost and a higher completion frequency. 

Now, I'm not saying operators aren't still trying to optimize their production and get every last drop they can.....I just haven't seen any big changes in that arena in a long long time and it seems like the production data supports that opinion.

All that being said, I can't foresee the next "big thing". There might be something out there I've never heard of or considered that will turn this whole argument on its head with it's obvious advantages. Please someone let me know as I would like to make money off of it.

So you're out there, what are you seeing? Faster cheaper wells, but how much oil is coming out of them? Have they drilled all the sweet spots? Are you still working?

[PE Scott + 563]

14 minutes ago, DayTrader said:

No!! A or B buddy, sort it out, there is no place for fence sitters here. You are A. 

Damnit, all that effort for nothing!

[Jabbar + 465]

54 minutes ago, James Gautreau said:

I disagree. Decline rates are so high they will overwhelm any attempts to keep production flat, let alone growing. The new wells are done so fast they won't comeback until $150 oil if ever. If you have to drill 4 or 5 wells to find 1 good well that is now defined as 200,000 barrels EUR, than you need $250 - $300 oil to make it work. Just to offset 2018 decline 250,000 bpd per month you need 400 DUC's -700 bpd  X 400 or 280,000, and that is just for one year. Take all the other years and you're probably double that or 500,000 or 600,000 bpd per month. So headed into next year you'll have to do  500 - 1000 DUC's a month. 7500 DUC's don't seem like many then. And that number is growing fffffast, I'm guessing it'll be 1,000,000 bpd per month by summer. That's  why when the decline starts it will be breathtaking. They have set this up beautifully, because 99% of people do not know this train is coming down the mountain. 

Better start building my backyard bomb shelter.  

[PE Scott + 563]

7 minutes ago, James Gautreau said:

So you're out there, what are you seeing? Faster cheaper wells, but how much oil is coming out of them? Have they drilled all the sweet spots? Are you still working?

I'm not sitting a frac at the moment....or until January, but I'm still working. I'm doing some design work for some wells in SE New Mexico for a smaller company at the moment. Theyll be drilled in Feb, completed in March. Fingers crossed I land a long contract with a larger private company that will keep me busy through September. That's the oilfield though, you either have the gumption to handle it or you don't. I rather enjoy the hustle, so it suits me.

From a design perspective, cost is one of the biggest limiting factors. We can use all sorts of fancy ceramic proppants, guar based gels, 20 pumps running 120 bpm down a massive monoline, etc. All of these things could effectively increase recovery, but you see diminishing returns at some point that dont make it economically feasible. 

In TX and NM i think there are plenty of sweet spots left to drill, but they're not right next to the interstate anymore. For example, over the summer I was down by Laredo, TX on a job in the Eagle Ford....it was something like 21 miles from location to a paved road. I heard those wells were great though.

I'm not a production engineer so I'm not privy to all the details of that side with some of larger operators I do business with. However, of the smaller ones I've done design and field work for, we've basically trended with production from offset wells where the production was worth trying to emulate when normalized for lateral distance. We've seen a little better results pumping lower rates and dropping diverter to limit the frac length and target specific zones.....nothing crazy though.

[James Gautreau + 86]

3 minutes ago, PE Scott said:

I'm not sitting a frac at the moment....or until January, but I'm still working. I'm doing some design work for some wells in SE New Mexico for a smaller company at the moment. Theyll be drilled in Feb, completed in March. Fingers crossed I land a long contract with a larger private company that will keep me busy through September. That's the oilfield though, you either have the gumption to handle it or you don't. I rather enjoy the hustle, so it suits me.

From a design perspective, cost is one of the biggest limiting factors. We can use all sorts of fancy ceramic proppants, guar based gels, 20 pumps running 120 bpm down a massive monoline, etc. All of these things could effectively increase recovery, but you see diminishing returns at some point that dont make it economically feasible. 

In TX and NM i think there are plenty of sweet spots left to drill, but they're not right next to the interstate anymore. For example, over the summer I was down by Laredo, TX on a job in the Eagle Ford....it was something like 21 miles from location to a paved road. I heard those wells were great though.

I'm not a production engineer so I'm not privy to all the details of that side with some of larger operators I do business with. However, of the smaller ones I've done design and field work for, we've basically trended with production from offset wells where the production was worth trying to emulate when normalized for lateral distance. We've seen a little better results pumping lower rates and dropping diverter to limit the frac length and target specific zones.....nothing crazy though.

Interesting. So where are you at? Is oil production lower 48 peaking? It sure looks that way to me.

[PE Scott + 563]

1 minute ago, James Gautreau said:

Interesting. So where are you at? Is oil production lower 48 peaking? It sure looks that way to me.

I live in Albuquerque, NM. I work all over the U.S. but primarily in NM and TX. 

Honestly, it's hard to say. I have certainly noticed a reduction in work. Many of my friends have been laid off. However, I also see single well pads very infrequently. Less than 3 wells on a pad is pretty rare these days even. So from that point of view, it looks like the industry is doing more with less now which skews the effect of a dropping rig count. 

I guess it's hard to comment for me, like looking at an elephant through a microscope and trying to describe its body.

[Jabbar + 465]

3 hours ago, Rob Kramer said:

Just takes months .... as in MAY to DEC ... have they updated the latest "Technology" .... sorry just adding fuel to the fire. 

 

Conoco stated they are focused on five technology areas.  

KEEP IN MIND AS CONOCO STATED THIS IS IN THE DEVELOPMENT STAGE. Conoco has proven results and will fine tune and standardize the operational and processes in 2020 at three pads in Eagleford and one pad in the Delaware. They said full implementation in the lower 48 shale properties company wide in 2021.

The " Never Shalers" keep listing historical data and showing reams of meaningless graphs.  

They often harp on average yield per well. First, this is historical data (2) We're not talking about doubling yield per well ONLY. We are talking several things (1) yield per well is part and is increasing (2) diminishing the Parent/Child stack/spacing, thus increasing the number of wells in given section along with the increase per well production increase  is even more important.  

THEN add to that the efficiencies that digital technology from drsign, completion ,transport, marketing and exporting. You have a very efficient low break/even price structure.  

"Never Shalers" live in the past and in denial as it pertains to application of latest techology. Basically they are ludites. Debating them gets tired after a while and ya gotta move on to another discussion. 

No fire.  You have to realize the "Never Shalers" have an agenda.  Most are investors that have watched their stock holdings go down, others are former oil engineers with skills in conventional oil, some are Green teamers and some just like to argue for argument's sake.  

I enjoy a good debate but that's not what the " Never Shalers" do.  You tell them the sky is blue and they want ten scientific PhD papers that prove the sky is blue.

Example: Coyne says Conoco presentation does not say their test acreage yields 20%.  It does . So I then post  video of CTO saying just that. Now Coyne  says he's lying and "they have been claiming that since 2013"

Who cares what they believe ? 

OilPrice site proclaims to be developed for investors and wants to attract investors.  The "Never Shalers" just want to vent their angst which manifests into this visceral hatred for profitable shale companies.  I guess it's therapeutic.  Better than downing a bottle of Jack Daniels  . . .   well maybe not on that much better.  

There are some benefits. There are some knowledgeable members thst have application to today's oil markets .   .   .   .   and there are some discussions that have some witty posters that will make ya laugh every once in a while. 

 

Edited December 12, 2019 by Jabbar

[James Gautreau + 86]

7 minutes ago, PE Scott said:

I live in Albuquerque, NM. I work all over the U.S. but primarily in NM and TX. 

Honestly, it's hard to say. I have certainly noticed a reduction in work. Many of my friends have been laid off. However, I also see single well pads very infrequently. Less than 3 wells on a pad is pretty rare these days even. So from that point of view, it looks like the industry is doing more with less now which skews the effect of a dropping rig count. 

I guess it's hard to comment for me, like looking at an elephant through a microscope and trying to describe its body.

Can't tell from where you're sitting and you're sitting right in it. I hear you. Just looking for an edge. Well let me ask you this. I have read in forums and such that the rigs are getting dis-assembled and sold for scrap, like the rigs are never coming back. Halliburton is laying off quite a few people. Are they going to be able to turn this thing back on as fast as people think? 

[Jabbar + 465]

1 hour ago, PE Scott said:

I live in Albuquerque, NM. I work all over the U.S. but primarily in NM and TX. 

 

PE Scott

Conoco recently stated they're testing has allowed them to successfully drill 12 to 16 wells per section in the Delaware.  Are you seeing anything close to that in N.M. 

NOTE: these are all test wells at this point.  Conoco said they will test on one pad in Delaware this year with full implementation in 2021. Also, stayed 20% yield for given section and "we can do even better" 

Edited December 12, 2019 by Jabbar

[PE Scott + 563]

8 minutes ago, Jabbar said:

PE Scott

Conoco recently stated they're testing has allowed them to successfully drill 12 to 16 wells per section in the Delaware.  Are you seeing anything close to that in N.M. 

No, more like 9 wells when they're spacing them kind of tight. You're on to something there though. Well spacing is a huge hurdle. Technology that's helped that would be seismic monitoring from offset wells. They can give you an idea of where and how far the fractures are propagating which will then help inform your well spacing on the next project. The trick there is not spacing them too tightly and completing them in the right order.

That speaks less to drilling and completion technology and more to reservoir management/planning in my opinion though. Or, more specifically, the individual wells aren't producing more from the surrounding rock. Their drainage area and percentage hasn't necessarily increased. However, those larger companies have figured out how to produce consistent-ish results with small changes in frac design so that the reservoir team can space wells closer with greater confidence and thereby achieve a greater overall recovery from the reservoir. That's one of the reasons I think the big boys will have an advantage in the Permian. 

Another thing that may be different is designs are a bit more forward thinking now in terms if re-fracs. I have done some re-fracs for smaller companies when I was still with a service company (C&J - Lousiana) and they mostly turned out well and brought production up near levels seen when the wells were first completed. These are dry gas reservoirs though and behave differently than the permian.

I'll try to find it, but I was recently reading an SPE paper about completions in the Eagleford and Austin Chalk that suggested there could be a benefit to completing the wells in such a way they would communicate. Of course, that could all be nonsense too. I haven't looked into it that much.

[PE Scott + 563]

1 hour ago, James Gautreau said:

Can't tell from where you're sitting and you're sitting right in it. I hear you. Just looking for an edge. Well let me ask you this. I have read in forums and such that the rigs are getting dis-assembled and sold for scrap, like the rigs are never coming back. Halliburton is laying off quite a few people. Are they going to be able to turn this thing back on as fast as people think? 

Probably, yes. I say this because service companies, by necessity, have learned to operate on a lean budget with fewer personnel. Equipment has improved to the point that a less skilled operator is capable of doing what would have previously been considered a complex task. Frac designs have become simpler, mostly relying on slickwater systems that don't use guar based gels and the required hydration units, equipment operators, and fluid techs to operate. Field engineers are all but a thing of the past, their task now being handled remotely by a much smaller number of people.

So, I think the sad reality is the oilfield won't NEED to hire back all the personel they've released. Equipment can be ramped up just as quickly as it was the last time assuming the $$ are there to support it.

Edited December 12, 2019 by PE Scott

[PE Scott + 563]

1 hour ago, Jabbar said:

Conoco [said] they are focused on five years geology areas

 

 

Purely speculation on my part, butI think this is probably the bigger factor by which investment in shale hinges. The real advantage shale has over conventional off shore assets is a relatively short ROI....assuming completion cost and production allows for a reasonable ROI.

Off shore assets are based on outlooks over decades, 50 years even. So the question you have to ask yourself is, from an operators perspective, what is your confidence in oil demand and price over the next 50 years? Vs, 5 years? 

So, assuming they can still make money on shale, I think it will remain an attractive investment as the oil sector is concerned. Again, this is all speculation on my part. Please no one get upset with me if its contrary to your point of view....I could very well be wrong.

 

Edited December 12, 2019 by PE Scott

[Boat + 1,324]

On 12/10/2019 at 8:20 PM, Douglas Buckland said:

Once again you have managed to avoid defining any new technologies which are somehow going to transform the shale oil game in the future. Hydraulic fracturing, horizontal wells, multi-lateral wells, etc...have been around for several decades.

No, I am not Russian, simply a rational adult. 
 

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. 

[James Gautreau + 86]

4 minutes ago, PE Scott said:

 

 

Purely speculation on my part, butI think this is probably the bigger factor by which investment in shale hinges. The real advantage shale has over conventional off shore assets is a relatively short ROI....assuming completion cost and production allows for a reasonable ROI.

Off shore assets are based on outlooks over decades, 50 years even. So the question you have to ask yourself is, from an operators perspective, what is your confidence in oil demand and price over the next 50 years? Vs, 5 years? 

So, assuming they can still make money on shale, I think it will remain an attractive investment as the oil sector is concerned. Again, this is all speculation on my part. Please no one get upset with me if its contrary to your point of view....I could very well be wrong.

 

Capex shows where companies are spending. Over the span of 2014-2016, oil companies reduced their capex the most in history. That means there's only a few of those long lead time, long production times coming on first half 2020. After that it's done. 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. 

[Boat + 1,324]

51 minutes ago, PE Scott said:

Probably, yes. I say this because service companies, by necessity, have learned to operate on a lean budget with fewer personnel. Equipment has improved to the point that a less skilled operator is capable of doing what would have previously been considered a complex task. Frac designs have become simpler, mostly relying on slickwater systems that don't use guar based gels and the required hydration units, equipment operators, and fluid techs to operate. Field engineers are all but a thing of the past, their task now being handled remotely by a much smaller number of people.

So, I think the sad reality is the oilfield won't NEED to hire back all the personel they've released. Equipment can be ramped up just as quickly as it was the last time assuming the $$ are there to support it.

In 1900 95% of the population were farmers. Last I looked it was down to 1.3% why would FF energy employment be any different. 

[PE Scott + 563]

2 minutes ago, Boat said:

In 1900 95% of the population were farmers. Last I looked it was down to 1.3% why would FF energy employment be any different. 

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.

[jjj + 26]

1 hour ago, James Gautreau said:

Can't tell from where you're sitting and you're sitting right in it. I hear you. Just looking for an edge. Well let me ask you this. I have read in forums and such that the rigs are getting dis-assembled and sold for scrap, like the rigs are never coming back. Halliburton is laying off quite a few people. Are they going to be able to turn this thing back on as fast as people think? 

James,

I can't answer all your questions but on rig disassembly I can give some clarification. The market has moved from traditional diesel rigs to DC rigs to A/C rigs. Even on a A/C rig so much technology has changed in the last 10 years that a 10 year old rig will need a major upgrade to be competitive today. What they are disassembling are obsolete rigs that do not have the new technology built in and the company has decided that they are not economically feasible to upgrade. In addition during the 1st shale boom everybody wanted new rigs and many were built that were junk from day one. (I know I built a few of the junk ones before learning).

Basically pre-shale rigs were just dumb steel that could have new fancy controls added it didn't matter if the rig was 30 years old or not. After the shale drillers discovered that the price of oil wasn't going to stay above $100 all the time they started figuring out how to drill for shale economically. That focus has driven so many changes into a rig that they can not just be added to the old steel anymore. 

I still have a few contacts in the rig business and all their domestic work right now is in updating rigs that were built after 2012-ish to today's standards. Older rigs are just being scrapped.

Jay 

[PE Scott + 563]

34 minutes ago, Boat said:

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.

You see, I agree that this kind of "tech" has helped decrease completion cost and thus improve margins on newer wells.

I also agree with @Douglas Buckland though that there hasn't been a hole lot of technology improving the ultimate recovery in the horizontal.  Like you say, @Boat, there are little tweaks here and there to frac design that help improve things, changes in chemicals that have reduced detrimental skin effects, things like that. However, I have to concede that I haven't seen anything groundbreaking that's going to greatly enhance production, yet. 

I don't think that really matters though. Operators have learned their lessons about being overly optimistic. Theyll lick their wounds and use what they've learned to make money moving forward. Just my opinion.

[Rob Kramer + 696]

41 minutes 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. 

This is the reason why Jabbar and Douglas are at odds . Guy A as DT said is calling efficientcy gains and a different use of current technology a new technology and Guy B is saying those were invented years ago and have been used in different manners before.

[Rob Kramer + 696]

PE you get an award for beating me to it and for having the most useful info .... EV reliability and hands on shale ! 

Edited December 12, 2019 by Rob Kramer
Me and PE are Guy C

[PE Scott + 563]

13 minutes ago, Rob Kramer said:

PE you get an award for beating me to it and for having the most useful info .... EV reliability and hands on shale ! 

Lol, right place, right time. If only I could always be so lucky!

Edit: I was just reflecting on how random it is that my ownership of an EV and my occupation as a completion engineer would both be pertinent in the same thread. Only at OilPrice

Edited December 12, 2019 by PE Scott

[James Gautreau + 86]

33 minutes ago, jjj said:

James,

I can't answer all your questions but on rig disassembly I can give some clarification. The market has moved from traditional diesel rigs to DC rigs to A/C rigs. Even on a A/C rig so much technology has changed in the last 10 years that a 10 year old rig will need a major upgrade to be competitive today. What they are disassembling are obsolete rigs that do not have the new technology built in and the company has decided that they are not economically feasible to upgrade. In addition during the 1st shale boom everybody wanted new rigs and many were built that were junk from day one. (I know I built a few of the junk ones before learning).

Basically pre-shale rigs were just dumb steel that could have new fancy controls added it didn't matter if the rig was 30 years old or not. After the shale drillers discovered that the price of oil wasn't going to stay above $100 all the time they started figuring out how to drill for shale economically. That focus has driven so many changes into a rig that they can not just be added to the old steel anymore. 

I still have a few contacts in the rig business and all their domestic work right now is in updating rigs that were built after 2012-ish to today's standards. Older rigs are just being scrapped.

Jay 

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?

[James Gautreau + 86]

Here is some data from a different source than shaleprofile.com and it says pretty much the same thing in a slightly different way. 

https://www.oilandgas360.com/permian-drilling-must-pick-up-just-to-maintain-current-production-report/

[Coffeeguyzz + 454]

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.

[PE Scott + 563]

15 minutes ago, James Gautreau said:

Here is some data from a different source than shaleprofile.com and it says pretty much the same thing in a slightly different way. 

https://www.oilandgas360.com/permian-drilling-must-pick-up-just-to-maintain-current-production-report/

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.