Thursday, August 3, 2017

E&P decoding - Pioneer Natural Resources edition

I think I know what this means but as per usual the internet is full of people who know far more than me. You dear readers are my 20 thousand person expert network. 

This is from the Pioneer Natural Resources conference call. I would really love people to explain it - preferably word-by-word in the comments. In particular I want to understand the drivers of the pressure changes (which matters for proppants for instance) and how the four-string casing deals with the problem.

Thanks in advance:

We've mentioned this in all the slides and such, but we did fall behind operationally on our completions in the Spraberry/Wolfcamp, in large part due to unforeseen drilling delays. What happened is the delays were really the result of unexpected changes in pressure regimes in the field.  
So what we've seen is increasing pressures in some of the shallow formations that means we have to mud up substantially to deal with that problem and then we immediately then are drilling into lower pressure depleted zones. And we were at the knife's edge of this really through all 2016. But these pressures have changed in a subtle manner such that we now find we had a higher percentage of what we refer to as train-wreck wells, where we have all kinds of problems with lost circulation and other issues because of this pressure change. 
The easiest way to remediate this is with a drilling plan takes us from a three-string casing design to a four-string casing design. So that's exactly what we've done. We solved this issue. We have addressed it and we've done so by changing the casing design, which has proven to be very successful. 
One thing it does is it does increase the well cost substantially, about $300,000 to $400,000 per well, and it does increase our time of drilling five days or so. But we're also nickel-and-diming away other costs in these wells to try to get that money back, including changing out surfactants and other things to try to reduce costs and reduce days. So we're not going to stand pat with this increase. We're going to chip away at it and reduce it. 
Cumulatively, though, what happens is because we've impacted the schedule, we've also then reduced the number of POPs we're going to be completing this year by about 30. Those essentially will move into 2018. That's 100% due to these drilling delays I mentioned, which I believe we now have mitigated. But you have to also factor in the delays not only result in the deferral of wells you put on production, but also loses production days for all the wells that get delayed that are going to be POP'd in the future, particularly later in the next year. But the point is we're now dealing with that. I think we have that squared away. I have a later slide we'll talk about more detail on that.



14 comments:

Anonymous said...

"So what we've seen is increasing pressures in some of the shallow formations that means we have to mud up substantially to deal with that problem and then we immediately then are drilling into lower pressure depleted zones. And we were at the knife's edge of this really through all 2016. But these pressures have changed in a subtle manner such that we now find we had a higher percentage of what we refer to as train-wreck wells, where we have all kinds of problems with lost circulation and other issues because of this pressure change."

When you are drilling an oil and gas well, you drill through layers of differential pressures due to rock type, water saturation, etc. When there is a zone that has lower pressure, you have to increase your mudweight in order to keep the zone of rock from crashing in on you or losing control of the well (http://www.glossary.oilfield.slb.com/Terms/l/lost_circulation.aspx). When you have loss circulation, it's not safe to continue drilling until you fix the problem. (Macondo's blowout was in part pre-saged by a loss circulation event)

One big reason why you might have lower pressure in a particular layer is depletion: if that layer was previously drilled for oil and gas, taking that oil, gas and water out lowers the pressure. The Permian has been drilled for 90 years, but until 10 years ago it was drilled vertically with shallower conventional formations driving most of the production. Here's the key: Pioneer's Midland Basin land has had a lot more vertical drilling on it historically than others like Parsley, FANG, etc. That means more areas of potential depletion and loss circulation events in shallower zones, especially as Pioneer increases the number of wellbores they are drilling.

"The easiest way to remediate this is with a drilling plan takes us from a three-string casing design to a four-string casing design. So that's exactly what we've done. We solved this issue. We have addressed it and we've done so by changing the casing design, which has proven to be very successful."

One way you remediate this lost circulation is by setting steel casing over the depleted zone. This effectively seals off the problematic zone. The issue is that setting casing costs time (you need to trip out of the hole with your bit, set the new casing, test it's integrity, trip back in, and start drilling again) and money (dayrates on equipment, money for the casing itself, etc). What Pioneer is saying is that in depleted areas, they are having to set an extra string of casing which costs $300-400k/well and time.

All of these shale company budgets are based off of a "manufacturing process" of pads, lowering days drilling, etc. If your wells take an extra 5 days to drill, that sets a pad completion time back 5x the number of wells and you see that effect in the lowering of guidance. The key is how widespread this problem is for Pioneer/others in the Midland and whether they can get better at it over time. I have no idea on the answers to those questions, but you can check on the Texas RRC to see where vertical well density is the highest and potentially where Pioneer's problematic wells are (would take some digging and detective work).

By the way, this is all in the vertical section of the well. It has nothing to do with completions or proppant as far as I know.

Cult of Permaniacs said...

I much prefer when you write businesses with an actual competitive advantage! Energy is no fun…

I interpreted comment as the idea they are running another intermediate casing string in order to manage the pressure/improve drilling process in the shallow portion of the well (probably vertical section as they state it is at 3-4k ft though maybe the build up portion if it’s a shallow well; it's definitely not in the horizontal or producing portion of the well; you can see the San Andres isn’t too far above Clear Fork - which is PXD's shallowest Hz target to my knowledge - in Midland Basin here: http://www.beg.utexas.edu/resprog/permianbasin/data/posters/FuhrmanMascho_field/FMU_SanAndres_poster1_1.pdf). Assuming they run the extra casing string in middle of drilling process (which is how I understood comment), using another casing string would allow them to seal off the overpressured part of the well when they drill the underpressured part that follows. This costs money directly (another “SKU” of OCTG, another cement job) but shouldn’t be huge direct cost if you believe the 75% IRR. Bigger issue is that running casing takes time and time is money when on a wellsite.

I have heard managed pressure drilling techniques have been moving from offshore and into the Delaware Basin; this issue makes it seems as if they might be appropriate for Midland as well (though due to produced water induced changes in pressure as opposed to geological). Dayrates for MPD offshore were like $30k a couple years back – obviously would need a steep price cut to make work in unconventionals.

Based on my conversations with geologists (I’m just an excel monkey), I’ve always had an issue with the idea (which is strongly implied by the E&Ps, if not claimed outright) that the Permian’s various layers or benches are homogeneous throughout each basin. There is a lot of variability, even with the improved well control brought by the shale revolution, and what one encounters in one well may be varied from what one encounters a couple miles down the road. “Manufacturing mode” will be a struggle…

Pemcap said...

https://www.horsemancapital.com/marketviews/russell-clark/2017/07/the-end-of-the-texas-tea-party

Also made me think of this https://seekingalpha.com/instablog/957061-chris-demuth-jr/3170505-spotting-lies-for-fun-and-profit

Anonymous said...

-> What happened is the delays were really the result of unexpected changes in pressure regimes in the field.

Well control covers the management of drilling activities with respect to formation pressure gradients. Oil and gas is under pressure when it is underground. A reservoir can be overpressured, underpressured or normal pressured, with normal pressure defined as the pressure exerted by a column of water as tall as the well is deep. If you have oil and gas that is trapped in the formation and heavy overburden bearing down on it, you’ll have an overpressured formation. The pressure of the formation determines the mud weight necessary for drilling. The bottom hole pressure always has to be above the formation pressure, otherwise the formation fluids (the o&g) will shoot up the well in what is called a kick, which can result in a blowout, which is bad (expensive, dangerous, etc).

-> So what we've seen is increasing pressures ... we were at the knife's edge of this really through all 2016.

Pioneer is having issues with their shallow wells. They are hitting areas of excess formation pressure, which leads to their having to use a heavier mud to prevent a blowout. Right next to the overpressured areas, they are hitting underpressured areas, which can occur when all of the o&g has already been exploited and formation pressures released or for geological reasons. They are then overweight in their mud for that drilling. Very hard to control.

-> But these pressures have changed ... because of this pressure change.

I think you can figure out what a train wreck well is. Lost circulation happens in underpressured areas. Drilling mud goes down the middle of the drillpipe, drives the bit, and then returns up the sides of the wellbore to be recycled. When you hit an underpressured area, you can end up with lost circulation, where there isn’t enough pressure to drive the mud back through the recycling process, so not only do you have to add more mud to compensate for what was lost (expensive), but you also risk a blowout should you hit another high pressure area.

-> The easiest way to remediate this ... which has proven to be very successful.

A casing string is a section of pipeline lowered into a wellbore. There are many different types of casing that vary based on size, strength, material, etc. Pioneer has gone from 3 types of casing to 4 in their wells to compensate for the formation issues. This is more expensive and labor intensive, but solves a lot of their problems, according to them.

-> One thing it does is it does increase the well cost substantially, ... We're going to chip away at it and reduce it.

Wells are now more expensive and slower to drill.

-> Cumulatively, though, what happens is because we've impacted the schedule, ... I have a later slide we'll talk about more detail on that.

Because of the crappy wells and the newly increased drill times, Pioneer will complete less wells than expected this year. This also pushes future wells back. It is possible that they may also take an extra 5 or so days to drill relative to expectations, so potentially everything is now slower and more expensive.

This should be a broadly correct interpretation. Happy to be corrected if anyone finds errors.

Stevie B. said...

John, the pressure changes aren't really anything to do with the fracking process so no impact on propane or the completion. The problem is the pressure in the overlying formations and the target formations is deviating from the normal hydrostatic pressure.

You see as you drill deeper the pressure increases - if a zone is "normally" pressured then the pressure at depth is the same as if you had a column of salty water all the way to the surface. So you can hold that pressure back with a column of mud that weighs just a bit more than salty water.

If the zones are overpressured - like Pioneer are getting here then you need heavier mud to stop fluid coming into the well in an uncontrolled way (a bad thing). That's OK until you drill into one of the depleted (under-pressured) zones deeper down then the mud is too heavy and rushes into the formation - that's called getting losses. If the losses happen too quickly you can end up without enough mud in the well to stop the fluid from entering the well in an uncontrolled way (a bad thing).

So what you need to do is to case off (run another string of casing) the high pressure zones before you drill into the under-pressured zones.

It's not really a big deal but running another string of casing means that you have smaller diameter tubing in the zone you want to produce from and it costs time and money so Pioneer will be disadvantaged compared to operators who don't have shallow overpressured zones and depleted deeper zones to contend with.

Damned if I know what the acronym POP stands for though, I am more of a North Sea tiger than a Texas driller.

Anonymous said...

Real simple, stay very far from all E&P companies.

The E&P industry's profitability record is laughable.

Anonymous said...

Hi John - a disclaimer, i'm not a field guy i'm a finance guy, but I've covered this space for 13 years, so i'm going to take a shot at translating.

(1) the problem appears to be with formation pressure changing while drilling (and before fracing) which causes issues with the drill string. The easiest way to combat this is to increase the pressure of the drilling fluid ("mud") to hold back the formation pressure, to allow the well to be drilled

(2) if you do this, the well becomes more risky and prone to collapse prior to reaching total depth. So a way to address THAT risk, is to increase the number of casing strings. A casing string is basically a "save point" (to use a video game term). As you drill a well, it is "open hole" meaning it's not so much a well as a cliff down into the ground. Cliffs are unstable and can fall or sluff. So you use drilling mud to hold back the sides of the well while you drill. But to "lock in" the well permanently, you'd lower in steel production casing, and cement it in place. the cheapest way to do this is to wait until the whole well is drilled and then case the well. but that's risky. and if the formation dictates high pressures, then you may want to put in intermediate casing so if your formation collapses below, you don't lose the whole well (or so you can use different mud pressures, because the above wellbore is already cased ie: sealed)

(3) i'm not sure what if any impact this would have on proppant. the fracing (completing) part of a well typically occurs once the whole well is drilled, and most (or all) of the well is cased too. Unless it's an open hole completion, in which case teh vertical part of teh well is cased, and the horizontal is left open. it COULD imply that the formation pressure at depth is high, which suggests greater frac pressure, but the way Pioneer describes it, it sounds like it is the pressures as the well is on it's way to depth (rather than at depth itself).

this would be a lot clearer if i could draw a picture, but hopefully this helps.

Sorry about the crappy grammar & spelling ... i'm up late (ET) going through quarterly results, and this was a welcome detraction while i waited for the next guy to report, which has now happened. so I'm going to dive back in.

Good luck -

Annon

Tom said...

You have a great set of technical explanations above (particularly anonymous at 0726 and Stevie B at 0746). The business impact is
1. costs increase per well. Material costs increase (mud, extra casing, cement) and drilling time per well increases which has a direct cost impact)
2. rate of revenue build reduces. As these wells are pushed to the right the expected revenue from production is delayed.
3. fewer wells are completed (Put On Production) in each accounting period so cash generation potential per period is reduced.

So key financial performance metrics will degrade including capex per barrel cost and aggregate working capital will need to increase.

Another point to focus on is the reference to "train wreck" wells. The phrase is easy to grasp - it is a bad thing - but the inherent unpredictable nature of a train wreck means you could be stuck on a single well for a long period of unproductive time and it may require the well to be "junked" and re-drilled. The more cautious approach being described by Pioneer mitigates this risk but does not remove the risk altogether.

The other point worth reinforcing is raised by Stevie B above. By setting an extra casing the diameter of pipe in the reservoir (producing) zone is lower. The driving force to expel oil and gas comes from the pressure in the reservoir. This is capped at initial conditions and reduces as you deplete fluids from the reservoir. If you have a smaller pipe over the reservoir with the same pressure regime you will experience lower flow rates. You would need to understand the specifics of the reservoir and completion design to model accurately and compare with other producers but it seems likely that these wells will produce at a lower rate at some point compared to a three casing design. This translates into lower productions, lower revenue and reinforces points 2 and 3 above and potentially increases average opex per barrel (if opex is largely fixed but production is lower).

Hope this is helpful.

James Battle said...

http://phx.corporate-ir.net/External.File?t=1&item=VHlwZT0yfFBhcmVudElEPTUyMDY0MzV8Q2hpbGRJRD02MDQzMDc=

Dec 31, 2015 - Average time to drill, complete and place a 3-well horizontal pad on production (spud-to- POP) reduced to 135 days in the Spraberry/Wolfcamp.

Anonymous said...

Most of what has been said to date in the above posts is true

1) Having over pressured and under pressured permeable zones/formations open in the same hole section can be a big problem (Really what matters is the pressure difference between the 2 zones regardless of which zone is abnormal or subnormal). Drilling mud is too dense for the lower pressure zone or too light for the over pressure so you are either losing or gaining which is not good. Although losing is better than gaining! Worst case is an underground blowout with fluids moving from over pressure to lower pressure, a situation that is very difficult to stop.

2) The problem might be solvable by pushing the previous casing string deeper to just cover the high pressured zone. They probably tried this and it didn't work, with the mud weight required too dense for the even shallower zones to handle.

3) The problem may be solved by using Managed Pressure Drilling techniques but MPD in a specific area comes with a learning curve and additional cost not only in equipment / personnel but also in time as normal tasks go more slowly.

4) The extra casing string not only costs in rig time, and money for the pipe and cement, but the casing strings and hole sizes above that normally have to be upsized - which is yet more cost for larger casing, more cement, more drilling fluid, slower drilling due to larger hole size, etc. The wellhead components (an extra section) may have to change also. In other words a compounding effect. Slim hole casing can work for the extra string - thus preventing the upsizing of shallower casing strings, especially in hard rock areas (Permian), but the hole size to casing clearance is tight making cementing operations more difficult. Perhaps, this is what Pioneer has done.

5) My theory on what is behind the "unexpected" higher pressured zones is that they are drilling their new wells near or in old oil fields that have been waterflooded. In those old waterfloods the injection of water for years, at relatively high pressure, can cause unintended problems. If an injector well has a poor primary cement job, the water being pumped into that well will often move behind the casing into higher zones thus causing the higher "unexpected" shallow pressure. In this case the first thing to try when drilling a new well is to shut down the injectors in the immediate vicinity of the new "shale" well. But that may not solve the problem.

6) Decades ago Pioneer was a notoriously low cost operator when they were mainly playing the Sprayberry in the Permian. The Sprayberry had very low production rates and the only way to make it economic was to chase every penny. If they are having to deal with the results of bad or inadequate cement jobs in their old oil fields now because they didn't design and pump proper cement jobs then - they deserve it. To me it looks like their corner cutting, and bragging about how cheaply they could drill then, has come home to roost.

Craver of cheaper gas said...

John is excellent and more... From the total wells, what is the percentage of wells that have the problems of the pressure changes (which matters for proppants for instance) and how
wells need the four-string casing, what is the
Percentage of wells that need four-strings casings from the total wells as a percentage. How many wells need the extra $300K to $400K, what is the percentage of wells to total wells that need the extra $400K to $300K. What is the % decrease on the gross margin and net margin from 2017 to 2018 due to the wells needing the $300 to $400 extra. When did they start having to add in cost $300K to $400K to the wells. How many train wrecks wells do they have now, what is the percentage to total wells of train wreck wells.

Craver of cheaper gas said...

John is the best by far

Close ended questions please submit your best approximation. 1) Does anybody know how to do a profit and loss of one singular well can you please
put it here 2) What is the percentage $300K to 400K of the total cost to run a well. 3) Is the referred $300K to 400K a fixed cost or a variable cost 4) what is the total cost to pump a wells, is it stablished per barrel or per well 5) How many wells need the extra $400,000
to $300,000, 6) What is the percentage of total wells to the ones needing the extra $400,000 to $300,000 . 7) What is the impact in the net and gross margins of the extra $400,000 to $300,000 8) How many current train wreck wells presently, 9) how many possible train wrecks wells. 10) Was this problem self induced by cutting corners in attempts for "cost savings" or this is a natural cost of doing business

Anonymous said...

As wells get longer, you run into more heterogeneity along the length of the lateral, both in geology and in pressure. Adding another casing string effectively segments the well into shorter intervals. It's a way to deal with that heterogeneity.

Anonymous said...

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thanks

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