Marina Schwarz

Exxon, Chevron the New Permian Kings

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I think we talked about it somewhere but if I'm just imagining, here's the proof: Big Oil's the one who can pull off steady production growth in the Permian, not everyone.

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5 hours ago, JJCar said:

This along with other technologies in sensors, mapping, etc, etc   are allowing operators to avoid frac hits and Parent/Child horizontal drilling within 4 yards of each other avoiding and drop in yield

Mate, you have no clue what you are talking about. Frac hits are happening with wells drilled 1000 ft apart.

There is low tolerance to BS on this forum.

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7 hours ago, wrs said:

XTO drilled and completed 7 wells during March through December of 2018 and brought them on line at the beginning of this year.  The January production was 93,000 bbl oil and 383,000 mcf gas.  Even at 1/8 our monthly check is mid six figures which exceeds the checks we have gotten from our section with a modern lease where we get 25% and cost free royalty with payment for any flared gas.   We currently have two wells on that section.

Great info, thanks!

I agree with your assessment on cost to drill 7 wells; $8.5M ea seems reasonable. Would you agree, @Mike Shellman?

XTO got it lucky with the acreage - they don't have to pay $100K/acre which would of ~double expenditures.

Jan production equates to 429 bopd/well which is not the best initial production but some decline may have taken place.

91 acre/well is probably where they want to be. Infill "child" wells would produce substantially less and likely to drop "parent" wells production. Additional wells can be drilled as there is likely stacked shale.

Don't count on that 6-figure check to continue (unless oil price will jump) - production decline is brutal. Here is ExxonMobil wells in Permian (both TX and NM - chose your county) from shalepfofile (thanks, Enno@shaleprofile😞 https://public.tableau.com/shared/BM8SCB9XY?:toolbar=no&:display_count=no

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@DanilKa  Actually, no. If these are Delaware wells, costs will be more like $9.5-10.0MM. I just received some CVX AFE's that were $11.5MM. Remember, all royalty owners love all unconventional HZ plays and you'll NEVER hear a royalty owner question economics. Not ever.

Everybody now has their panties in a bunch about how good big integrated companies will do in the Permian. They will not be able to drill better wells, not for many years. They will monopolize services and squeeze those poor dudes until they can't make any money. They will throw R&D money at source water, I hope, and that's good, as is Chevron's no flaring policy. They will soak up takeaway capacity and what they don't make  upstream, they'll make amends for it downstream. As some point out they have less to no leasehold costs, Chevron anyway (Exxon paid over $6B for that BOPCO crap), and much higher NRI's make economics a lot better. Across 1.7MM acres Chevron's average NRI's are >0.9500. That reduces time to pay out by a year.

The Permian is perfect for the big boys; its like salmon swimming up river to their place of birth to die. 

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(edited)

I talked to the XTO company man at the site about costs to drill and each well is less than $1m to drill.  The rest of the cost is completion and that can range from $2-5m.  My independent operator is paying a little more to get them drilled but less for the completion because his working interest partner is HAL.  Our first well drilled in 2014 cost about $15m but that was because it was sidetracked.  The second well cost about $6m and I know this on these wells because I received the daily reports on the wells and on other wells he drilled.  

With respect to production, this is not a full month I don't believe.  There was no production reported for December and the plan was to begin ramping up the flow from the wells during January.  My experience with these wells is that the largest production occurs in the third or fourth month of operation.  In the first few weeks they are adjusting the flow by changing choke settings and also having to switch between chokes because of plugs flowing back.  It takes a while to get optimal flow on one well much less 7.  I expect the wells to produce 4kbbl/day when they hit the peak flow.  

The operational costs here will be low because they have put so much automation into the infrastructure.  That first picture is the LACT unit which will allocate production to each well and determine when to dump to the pipeline.  No trucks needed for anything.  The last picture is of the 12 inch water takeaway pipe which is in addition to an 8 inch pipe that goes to a different disposal facility.  This is a fully automated site and should have low operating costs. 

My independent has his own water source, his own water disposal wells and his own gas processing facility as well as connections to three different pipelines for product sales.  He has put all of his wells on LACT units and automated water disposal so that there is no more cost for trucking.  He told me three years ago his operational costs were about $35/bbl but now they are less than $20 with all the automation he has put in.  There is a lot of misinformation being promoted about shale from people who don't actually do it.

As to frac interference, that happens as far a way as 2600 feet.  Horizontal spacing should remain at 1300 ft from all indications but a wine rack geometry with 330ft vertical separation that maintains 1300 feet horizontal spacing seems to be what most operators are using right now.

 

@MikeShellman, 

Royalty owners like making the most money and we do care about economics as it's important to maintaining production. What we don't like is being HBP for a few dollars per year.

Edited by wrs
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4 hours ago, wrs said:

My experience with these wells is that the largest production occurs in the third or fourth month of operation.  In the first few weeks they are adjusting the flow by changing choke settings and also having to switch between chokes because of plugs flowing back. 

Shale wells peak within the first 7 maybe 10 days if issues arise... You're first month is by far the biggest... which ever operator is telling you 3rd or 4th month is stealing from you somehow. 

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(edited)

4 hours ago, wrs said:

I talked to the XTO company man at the site about costs to drill and each well is less than $1m to drill.  The rest of the cost is completion and that can range from $2-5m.

Make sense, but if they are not paying >50% of AFE for completion - they are not doing it right.

4 hours ago, wrs said:

With respect to production, this is not a full month I don't believe.  There was no production reported for December and the plan was to begin ramping up the flow from the wells during January.  My experience with these wells is that the largest production occurs in the third or fourth month of operation.  In the first few weeks they are adjusting the flow by changing choke settings and also having to switch between chokes because of plugs flowing back.  It takes a while to get optimal flow on one well much less 7.  I expect the wells to produce 4kbbl/day when they hit the peak flow.   

Best of luck with ramp-up. Drawing down too hard could be detrimental to EUR due to loss of near-wellbore conductivity. 

4 hours ago, wrs said:

That first picture is the LACT unit which will allocate production to each well and determine when to dump to the pipeline. 

Cycling of pressure is generally not a good idea as it deteriorates fracture conductivity. HEAL downhole system getting popular as it reduces slugging and pressure cycles it causes. But XTO won't take any advise from you how to operate their wells.

4 hours ago, wrs said:

He has put all of his wells on LACT units and automated water disposal so that there is no more cost for trucking.  He told me three years ago his operational costs were about $35/bbl but now they are less than $20 with all the automation he has put in.

$20 is a very high operating cost; I sure hope it not anywhere close to it.

4 hours ago, wrs said:

As to frac interference, that happens as far a way as 2600 feet.  Horizontal spacing should remain at 1300 ft from all indications but a wine rack geometry with 330ft vertical separation that maintains 1300 feet horizontal spacing seems to be what most operators are using right now. 

there is no way of squeezing 7 wells into one section and keep 1300 ft between them - only if you blessed with multiple formations and can do "wine rack". Hence I question viability of 25 wells.

Enjoy it while it lasts!

Fresh free report on Permian https://shaleprofile.com/permian-basin-report/

Edited by DanilKa
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(edited)

6 hours ago, wrs said:

There is a lot of misinformation being promoted about shale from people who don't actually do it.

And way more from those that do it. Ask shareholders how they feel about that. 

NARO estimates 12.5MM people in America own royalties. That's about 3.6% of the total population. I estimate about 4.3MM, or 1.3% of the total population have royalty under America's four major shale oil basins. Those 4.3MM folks have earned over $180B from 10 GBO and 117 TCF of gas...and Lord knows how much more from lease bonuses; I guess another $50B, easy. And still counting. They all love shale, talk it up whenever they can, embrace drilling commitments and Pugh Clauses in their leases that would choke a horse. Drilling commitments alone have led to massive over drilling and frac hits in all basins. It makes it difficult to pay back long term debt because shale oil companies have to stay on the drilling hamster wheel constantly. Over leveraged oversupply drives the price of oil and natural gas down and keeps prices volatile. The rest of the domestic oil industry in America is in the toilet and critical investment in exploration around the entire rest of the world stagnant, all because of US shale oil.  

Its terrific for America now, providing all that debt gets paid back; it won't be in another decade when its all gone. 

 

  

 

Edited by Mike Shellman
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On 3/6/2019 at 3:33 PM, Marina Schwarz said:

I think we talked about it somewhere but if I'm just imagining, here's the proof: Big Oil's the one who can pull off steady production growth in the Permian, not everyone.

● Production growth does NOT equate to profits.

This niggling little fact seems to get ignored, again and again and again and again and again and again and again and again and again and again and again and again in the U.S. Shale Oil industry.

I'm not holding my breath that Big Oil will actually be able to turn a profit along with that production growth.

Has anyone considered that if it costs a company more money to produce a product than it can sell that product for, an increase in production will be an increase in losing money for that company?

 

 

 

 

 

 

 

 

wordsmouth-1.jpg

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On 3/6/2019 at 12:09 PM, JJCar said:

Breakevens a dropping and will continue.

New technologies and more import drilling methodologies are dropping the break even in US shale to high teens low $20's for those that use (and can afford the technology) and it only gets better. 

With $20 B/E shale and sub $30 offshore oil prices will "balance" and "stabilize" at $45 to $55 per barrel.  

But the day of reckoning for oil price is coming. 

The adage that oil always go up still stands  . . .  until it doesn't. 

 

Thank you...

This i can live with........

Though i would rather the $45 than the $55...

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(edited)

On 3/7/2019 at 11:55 AM, Dan Warnick said:

Fascinating!

agreed...

this thread is the kind of stuff i come to this website to read about......

Edited by Illurion
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3 hours ago, Mike Shellman said:

It makes it difficult to pay back long term debt because shale oil companies have to stay on the drilling hamster wheel constantly.

I think that's the most succinct description of the problem I've suspected U.S. shale has, which was made pretty obvious during the 2014 crash. Also, it's not a coincidence Total is steering clear of shale. Monsieur Pouyanne said it straight out: shale is very capital-intensive.

50 minutes ago, Tom Kirkman said:

Has anyone considered that if it costs a company more money to produce a product than it can sell that product for, an increase in production will be an increase in losing money for that company?

Imagine someone figuring this out. What a world we would live in then!

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11 hours ago, Mike Shellman said:

And way more from those that do it. Ask shareholders how they feel about that. 

NARO estimates 12.5MM people in America own royalties. That's about 3.6% of the total population. I estimate about 4.3MM, or 1.3% of the total population have royalty under America's four major shale oil basins. Those 4.3MM folks have earned over $180B from 10 GBO and 117 TCF of gas...and Lord knows how much more from lease bonuses; I guess another $50B, easy. And still counting. They all love shale, talk it up whenever they can, embrace drilling commitments and Pugh Clauses in their leases that would choke a horse. Drilling commitments alone have led to massive over drilling and frac hits in all basins. It makes it difficult to pay back long term debt because shale oil companies have to stay on the drilling hamster wheel constantly. Over leveraged oversupply drives the price of oil and natural gas down and keeps prices volatile. The rest of the domestic oil industry in America is in the toilet and critical investment in exploration around the entire rest of the world stagnant, all because of US shale oil.  

Its terrific for America now, providing all that debt gets paid back; it won't be in another decade when its all gone. 

 

  

 

Mike, 

I read your posts with interest and hinestly see a lot of insigth. But I think you are missing point due to your personal involevement. Longterm Shale will not kill stripper wells or onshore conventional. It will kill certain offshore plays. Just wait 5 years. Change happens at the margin and offshore will be the real victim. 

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(edited)

The majors taking over the majority of shale areas could only be a benefit, long term. The pundits and other independents are projecting how much shale can be produced and mostly exported, which is long term stupid for our economy.

Exxon and Chevron have been spending huge amounts of money to buy, expand, and build new refinery capacity which can use shale oil vs. heavy oil. Costs on that extend over decades. At some point in time, their production will flatten when the new construction is full capacity. Their vision on this, is obviously to use this oil in their refinery process, rather than exporting it. I agree with Mike S., that their costs of drilling could not be much different than other independents. However, they make that up with savings on transportation and the spread between WTI and Brent when they refine their own oil. 

There has been a lot of discussion on the amount of increase the majors are projecting to increase within the next five years. However, when you look at it, that increase will only cover the refining capabilities of the new construction.

Edited by GuyM
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@Rasmus Jorgensen  Thank you for your comment. I am at the end of my oil career; the shale oil industry is not hurting me personally. There is an incredible amount of propaganda about shale oil's sustainability. It is an amazing resource in my country that is being mismanaged. Low prices and price volatility IS hurting the offshore industry, badly. I agree with you 100% and it is one of many ramifications to the shale oil phenomena that will ultimately hurt our long term hydrocarbon future, not solve it.

My "agenda" is to draw attention to how this resource can be better managed. For my country and my kids.

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@GuyM  Thanks. Your comments and observations will be welcome here and I hope people will listen to you.

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12 minutes ago, Mike Shellman said:

@Rasmus Jorgensen  Thank you for your comment. I am at the end of my oil career; the shale oil industry is not hurting me personally. There is an incredible amount of propaganda about shale oil's sustainability. It is an amazing resource in my country that is being mismanaged. Low prices and price volatility IS hurting the offshore industry, badly. I agree with you 100% and it is one of many ramifications to the shale oil phenomena that will ultimately hurt our long term hydrocarbon future, not solve it.

My "agenda" is to draw attention to how this resource can be better managed. For my country and my kids.

Sorry if read something wrong into your opinions. 

Contrary to most in the offshore industry I believe the competetion from Shale is good. Offshore was getting way too expensive - shale provided a much needed reality check. the new offshore we will see 5 - 10 years down the road will be a much different animal. 

price volatillity as a result of competetion is good. It's capitalism. 

ps. I agree that shale could be managed better. TRRC should for example put a ban on flaring to force building gas processing plants. 

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(edited)

16 hours ago, Someting about oil said:

Shale wells peak within the first 7 maybe 10 days if issues arise... You're first month is by far the biggest... which ever operator is telling you 3rd or 4th month is stealing from you somehow. 

Not in my experience but I only have 5 wells so far to speak to.   Four of them were first wells and one was a second.  Two of them were drilled at the same time on opposite sides of a section so were separated by nearly 4000ft.  It's mostly water coming back for the first three or four days or even a week or 10 days for some wells so the opportunity to hit max production isn't there because of frac water flow back.  

My original comment was about calendar months but even after 60 days I have seen well production increase.  The RRC data is produced at the end of each calendar month so it's not often the well starts producing right at the beginning of a month although it happened that way twice in our five wells, still, only once did it result in the max production.  If you are not associated with well production you won't have access to daily production reports but I did get them on the two we have with our independent operator and those wells didn't make their best production until the 2nd and 4th calendar months.  The first well had it's best production on it's fourth calendar month.  The first XTO well was completed right at the end of June 2016 and July 2016 was it's best output at 17kbbl but the next month it produced 14kbbl and it did that many other times since.  It's production in January was 12kbbl so the other 7 wells only produced as much in the same time as a two and a half year old legacy well.  Clearly the new wells aren't at peak production yet (I hope anyway).

We are not naive royalty owners and so while our ancestors had a bad lease, we do not.  We get the data on our Culberson lease but I don't have that level of data from XTO in Reeves or BHP so I have to guess from their aggregated information provided to the RRC.  The BHP wells also didn't make their best production until the fourth calendar month and they were drilled at the beginning of 2015.  The first three wells were done when the industry was still learning a lot.  I have the most detailed information from our independent operator, not the XTO people.  The only way I get information from XTO is by going out there and talking to the drill crews.  I did talk to the guy that was in charge of the flow management team and he told me he didn't expect peak flow in January.  

Edited by wrs
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13 hours ago, Mike Shellman said:

And way more from those that do it. Ask shareholders how they feel about that. 

NARO estimates 12.5MM people in America own royalties. That's about 3.6% of the total population. I estimate about 4.3MM, or 1.3% of the total population have royalty under America's four major shale oil basins. Those 4.3MM folks have earned over $180B from 10 GBO and 117 TCF of gas...and Lord knows how much more from lease bonuses; I guess another $50B, easy. And still counting. They all love shale, talk it up whenever they can, embrace drilling commitments and Pugh Clauses in their leases that would choke a horse. Drilling commitments alone have led to massive over drilling and frac hits in all basins. It makes it difficult to pay back long term debt because shale oil companies have to stay on the drilling hamster wheel constantly. Over leveraged oversupply drives the price of oil and natural gas down and keeps prices volatile. The rest of the domestic oil industry in America is in the toilet and critical investment in exploration around the entire rest of the world stagnant, all because of US shale oil.  

Its terrific for America now, providing all that debt gets paid back; it won't be in another decade when its all gone. 

 

  

 

I sense some sour grapes here.  You are a stripper operator I think, right?  The liars, er landmen are paid to sell these drilling commitments as inducements to sign the lease.  They pay bonuses too.  Getting the most for your assets is how you run a successful business.  If the operators are bad businessmen that is their problem. Please don't rain on my good business tactics with your sour grapes.

 

We collected $2.5m from Zaza back in 2013 for lease bonuses on about 3400 acres of minerals in the "Eaglebine" knowing we would probably never see a well and indeed, we got no production but we collected a lot of money.  This is the way the industry works, if you think we did something wrong by taking free money, please elaborate.  

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15 hours ago, DanilKa said:

 

there is no way of squeezing 7 wells into one section and keep 1300 ft between them - only if you blessed with multiple formations and can do "wine rack". Hence I question viability of 25 wells.

Enjoy it while it lasts!

 

We are certainly enjoying our income from all this oil production.  I am skeptical about how they are doing this but for now, the 8 wells they have drilled are all on the west half of the section still.  They haven't gotten to the east side yet.  The wine rack spacing works in the Wolfcamp because it's pretty thick.  There are multiple horizons in the wolf camp and the Bone Springs is just above the Wolfcamp and I believe it's producing very well in New Mexico bot not as good further to the south in Texas.  One of the XTO wells is a bone springs well.  

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(edited)

1 hour ago, Mike Shellman said:

@Rasmus Jorgensen  Thank you for your comment. I am at the end of my oil career; the shale oil industry is not hurting me personally. There is an incredible amount of propaganda about shale oil's sustainability. It is an amazing resource in my country that is being mismanaged. Low prices and price volatility IS hurting the offshore industry, badly. I agree with you 100% and it is one of many ramifications to the shale oil phenomena that will ultimately hurt our long term hydrocarbon future, not solve it.

My "agenda" is to draw attention to how this resource can be better managed. For my country and my kids.

 

This is what the "free market" produces in the oil business, always did and always will.  You are just on the wrong end of it in th stripper business.  

So you ascribe all the fault of the oil price collapse to shale and not KSA that wildly adjusted their production in 2014 to collapse the market by flooding it and again this summer to make Trump happy?  

Edited by wrs
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1 hour ago, Rasmus Jorgensen said:

Sorry if read something wrong into your opinions. 

Contrary to most in the offshore industry I believe the competetion from Shale is good. Offshore was getting way too expensive - shale provided a much needed reality check. the new offshore we will see 5 - 10 years down the road will be a much different animal. 

price volatillity as a result of competetion is good. It's capitalism. 

ps. I agree that shale could be managed better. TRRC should for example put a ban on flaring to force building gas processing plants. 

The gas processing plants are a chicken and egg thing.  You have to get enough gas production to make it worth investing in the processing and takeaway capacity.  It's getting built in Wolfcamp now but there was only one plant out there in the beginning and it blew up to smithereens in December 2015.

 

IMG_15891.jpg

IMG_15911.jpg

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15 hours ago, DanilKa said:

Cycling of pressure is generally not a good idea as it deteriorates fracture conductivity. HEAL downhole system getting popular as it reduces slugging and pressure cycles it causes. But XTO won't take any advise from you how to operate their wells.

 

The LACT unit should keep that from happening.  If trucks don't show up in time to empty the tank then the well choke has to be closed but with a LACT unit, the contract on the oil is done digitally and the unit empties the product into the line and gets an accounting that goes to the well operator and the pipeline operator.  It also measures the quality of the oil i.e. API and sends that too.  The tanks never fill up because the LACT unit always empties them before they get too full.  It's very automated and part of what lowers the cost per barrel operational costs.

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