The labels in the chart above are for the “corrected (3 month)” estimate. This estimate (now preferred by Dean Fantazzini) is 35 kb/d lower than the EIA estimate for Sept 2016 (which is the most recent EIA estimate). Texas C+C output has fallen by about 500 kb/d from the April 2015 peak.
Dean Fantazzini said the following in an email:
I am still using a 3-month window because, after the structural break in February 2016, the correcting factors are still decreasing (even though at a lower pace). As discussed earlier, there are 2 reasons for this phenomenon:
1) digitalization at Texas RRC, which should speed up the processing of data filings,
2) lower production, which clearly results in a quicker data processing.
At the moment, unfortunately, it is not clear which factor is more important: in the medium/long term, the digitalization process at Texas RRC should make Texas data reporting similar to North Dakota and Pennsylvania where production data are almost final and only the last published month is usually subject to smaller revisions. However, it is not clear how long this transition will take. This is why I keep on using a 3-months average of the Texas vintage data.
For the past three months the correction factors for C+C have been relatively stable, though potentially they may continue to fall so that RRC data will be relatively accurate after one or two months. For now the Texas data needs to be “corrected” by 434 kb/d for the most recent month, with decreasing correction factors for earlier months (104 kb/d for 9months earlier, Feb 2016). A Chart with correction Factors over time below.
The chart above shows how the 3 month correction factors have changed over the past three months, a decrease for the most recent months (month 1 and 2) of about 150 kb/d over those three months and about 50 kb/d for month 6. The correction factors converge after month 12.
If the decrease in the correction factors continues linearly (which seems optimistic), they would fall to zero within about 18 months. We will continue to watch closely to see how quickly the Texas data improves.
The Chart below shows how the “corrected” estimate using all vintage data has changed from July 2015 to Oct 2016. It is fairly clear that the estimates were too high from about Jan 2016 to Oct 2016, the recent 3 month corrected estimates may be better, we will have to wait for more data in the future to know for sure.
Chart below has Texas C+C data from March 2014 to October 2016.
Natural gas data is below. A new 3 month vintage corrected estimate is shown, 22,316 BCF/d in Oct 2016 a decrease of 398 BCF/d. The EIA reports 22,063 BCF/d in Oct 2016 an increase of 258 BCF/d.
Can anyone explain how come fracking is still affordable at the prices oil has been for most than a year.
You must not have been reading here.
Short answer is it is not affordable, but is done anyway with borrowed money.
The longer answer would explore why, but not now.
Excess natural gas storage largely gone. http://ir.eia.gov/ngs/ngs.html
http://americanoilman.homestead.com/GasStorage.html
http://americanoilman.homestead.com/gasstoragegraph.html
Although not directly related to natgas storage, (there is none, except some LNG), the wholesale price of electricity for New England’s grid briefly spiked above $320/Mwh early this AM.
That’s over ten times the normal rate.
Those folks sure could use some extra gas once winter gets underway.
Hi Coffee Guy,
When you say there is no storage, I presume you mean there is no gas stored where it can be delivered IMMEDIATELY to the natural gas fired generating plants in the New England area. In other words, the existing pipelines are inadequate to deliver as much gas as needed on extremely cold days.
Am I right about this?
And incidentally, for anybody who does know, where is the summer surplus production stored for winter sale in the US? Geographically? I presume there must be natural gas stored where there are old gas fields or the geology is suitable and pipelines are available to deliver and retrieve it as needed.
Is it politics or geology that prevents the folks in New England from building some gas storage infrastructure?
https://www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/undrgrndstor_map.html
It’s all politics- there should be plenty of gas available from Pennsylvania but they won’t let them build the pipelines.
OFM
There is a highly informative piece published June 26, 2016, in Forbes by a guy named Jude Clement.
His article contains a ton of links that really flesh out the whole New England natgas/pipeline/electricity situation.
Basically, as GJ’s link shows (tnx, GJ) there is no ‘backup’ amount of natgas in New England.
Being gaseous, it cannot reasonably be stored, although midstream companies can build looping pipelines to increase, somewhat, available supply.
There are only a handful of pipelines currently supplying New England, and cold temperatures cause much of that supply to be diverted from power generation to heating.
The decision makers up there have chosen a perilous course as there are few viable alternatives currently available.
New Canaan has chosen to bury underground propane tanks near schools and municipal buildings to ensure adequate winter heating.
Western Massachusetts has experienced a multi year moratorium on new gas hook ups which is affecting economic growth, along with increased utility bills for the entire region.
According to that ISO Express site, when temperatures rise a bit, wholesale electric prices plummet (was $17/Mwh briefly yesterday).
Crazy situation.
Best to install electric heat pump heating, methinks.
As for electricity, they clearly need more offshore wind, and more imported Canadian hydro.
This placed our local natural gas supply in a modestly precarious position. https://en.wikipedia.org/wiki/Aliso_Canyon_gas_leak
RW
Interesting, peculiar development from that Aliso Canyon leak …
Some fuzzy head discovered a new family of methane/ethane devouring microbes that had sprung up in the soil surrounding the escaping gas.
Story is related in Dec. 16, 2016 edition of LA Times by the author Khan.
Thanks every body for the comments.
It is my understanding that the UK and some other European countries do import a lot of gas during the warmer months for later winter use.
What sort of storage facilities do they use?
I remember reading about British generating plants not being able to get gas delivered FAST ENOUGH a couple of times although there was gas available in storage. Either the pipelines between the storage and the generating plants were inadequate , or else the gas couldn’t be gotten INTO the pipelines fast enough.
OFM
That is an interesting, and frequently overlooked, component to this situation.
Going from stored, LNG status, such as exists at the Everett terminal near Boston, (and, possibly, in the UK case you cited) requires vaporization, ie, turning the liquid methane gas , chilled to -260F and compressed to a 600 to 1 ratio, back into gaseous form so it can be introduced into the pipelines.
That is the bottleneck.
Standard LNG storage facilities are like huge thermos bottles.
Several of the New England anti-pipeline politicians are now clamoring for LNG infrastructure building before winter 2017-2018 sets in as large coal powered plant(s) operating today will be gone by then.
If they want them operational by next winter, they better get their Yankee asses in gear and put on a display of that good old vaunted Yankee giterdone.
Maybe I am a little too cynical, but I doubt they will even issue the permits before next winter.
I’m sure they can install solar panels, wind turbines, and a couple of batteries, and get by until they get a blizzard.
They certainly could install enough solar panels, wind turbines, and batteries, but they’d have to actually DO so. Those things cost money and do take months to install (years in the case of wind turbines). There seems to be a failure to bother to do anything going on.
“It is my understanding that the UK and some other European countries do import a lot of gas during the warmer months for later winter use.
What sort of storage facilities do they use? ”
Underground caverns in northern Germany and in the Vienna region of Austria. The former store around 4 months of the German annual demand, the latter around 6 months of the Austrian demand.
https://de.wikipedia.org/wiki/Untergrundspeicher
The best storage is located in Holland, near the Groningen hub. I believe one of the southern offshore fields was converted to storage, is hooked up to Great Yarmouth.
Spain has a facility called Castor Project, but they suspended its use after a small earthquake took place near Castellón, they think may have been triggered by gas injection. I reviewed the data and I think I know what happened but I’m not talking, I may want to write a paper about it.
Didn’t chart it, but reviewed completed new drills from the end of 2014 to Nov 2016. Nov 2016 was 264 compared to close to over 1800 a month at the high. I fail to understand how EIA can predict an upward slope the end of 2017. No way they can get enough frac trucks working by then. Forget how many wells they drill, it doesn’t come up until it is completed. It will continue to drop.
Hi Guy,
Only a 10 kb/d drop in Oct 2016,it won’t take a lot more completions to result in flat output, and a little more than that for an increase. However, I agree that the EIA estimates look too optimistic.
It was dropping when it went from 1800 to 1400. It was dropping when it went from 1400 to 900. It was dropping when it went from 900 to 500. If it goes back to 900, I expect a leveling out, and a slower drop. Probably, an increase in a couple of months, but an overall continuing drop, eventually. Texas had completions close to 1800 for about three years to bring the production up. Those wells are dropping now, and to level it out, there needs to be more completions happening than what will happen in 2017, in my guess. Take a gander at the number of producing wells, and their range of production on the RRC site.
Mis-statement. Around a 1000 wells a month for over three years, with a spike in 2014 of around two thousand wells a month. Those are the wells that are dropping fast.
Hi Guy,
My point is simple, look at the number of completed wells for the past 3 months or so and the rate of production decline. Let’s say the average was 350 new wells per month from August to Oct 2016 (I haven’t checked so it’s a guess), I am suggesting a small increase, maybe to 450 new wells per month stops the decline and maybe 550 new wells per month might raise output a bit. Eventually output falls, that is always true, the question is when, I don’t have an answer, but my guess is that by 2022 decline will be permanent for Worldwide C+C output, even if oil prices are high (over $100/b).
Not a lot of disagreement, here. Timing is all, and in that, there are no true experts. The elephant is too big to predict on a dime. Your statement seems absolutely correct, overall.
Hmmm. Permanent oil decline by 2022? Interesting. By 2022 I’m expecting all *new* cars to be electric, but the people still driving gas cars will be in for a world of hurt for the next 10 years. My projections don’t see us getting over 50% renewables until 2028 at the earliest, most likely 2029 or 2030. There should be a really nasty period in there between 2022 and 2030…
Hi Nathaneal,
World wide car sales in 2016 are expected to be 75 million.
If we assume new car sales do not decrease or increase, and that EV sales in 2016 are about 0.75 million Worldwide (this is actually plug-in sales, EV sales would be lower), then EV sales growth would need to be 1200% per year from 2017 to 2022 in order for 75 million EVs to be sold by 2022.
Does that scenario seem reasonable to you? It seems pretty unrealistic in my view.
Did you mean 120%?
I believe the current growth rate is 42%, which is pretty sustainable. That would get us to 50% market share in 12 years, after which exponential growth would be tough.
The EIA doesn’t release oil production projections by state.
As regards its forecasts for overall U.S. and Lower 48 states (ex GoM) output in 2017, they do not look too optimistic.
For the Lower 48 states (ex GoM), the EIA expects continued decline until March-April 2017 and only marginal increase (by 120 kb/d) by 4Q17.
U.S. oil production projections (mb/d)
source: EIA Short-Term Energy Outlook, December 2016
Annual average C+C output in Lower 48 states (ex GoM) is expected to decline by ~270 kb/d in 2017 vs. 2016. This is one of the most conservative forecasts.
Y-o-Y change in annual average Lower 48 states (excl. GoM) C+C production (mb/d)
sources: EIA oil production statistics; STEO December 2016; Annual Energy Outlook 2016 (released in January 2016)
The time lag between the start of the drilling and first production from LTO wells is 4-6 months. Hence, the most recent monthly production numbers, for October, reflect the record-low rig counts in 2Q16.
Since then, total U.S. oil rig count has increased by 61%; in the Permian basin – by 95%. Increasing rig count in the second half of 2016 will be reflected in slower decline rates in oil production in late 2016-early 2017 and return to moderate growth in the second half of 2017.
Time lag between drilling and production will increase as more wells are drilled. Not enough frac crews to handle additional wells. We went over EIA’s honky predictions on the GOM last post. EIA’s predictions are overly optimistic, in my opinion.
There was enough frac crews to add ~ 1 mb/d each year in 2012-14.
Even assuming that some equipment was scrapped in 2015-16 and part of workforce left the oil service industry forever, there is still sufficient unutilized fracking capacity for stabilizing output in 1H17 and very modest growth in 2H17.
I have never even been close to an oil well during the drilling and completion stages, but I have read all I could find about the actual hands on operations, and I don’t see that it takes very long for a man who is experienced in trades than use the same basic kinds of equipment, meaning tanker trucks, loaders, backhoes, dump trucks, bull dozers, industrial sized plumbing systems, hydraulic systems, electric motors, electrical controls, etc, to get to the point he can hold down a job on a fracking crew, so long as he has a more experienced coworker or a good supervisor.
The economy is not exactly running wild these days, and it ought not be too hard for a contractor to hire as many men as he wants, assuming he will pay decently. And unless I am mistaken, the wages paid to the on site crews amount to only a rather minor fraction of the total cost of a frack job.
Truck drivers, heavy equipment operators, industrial electricians experienced in field work, etc are cheap these days.
Does any body know how many EXPERIENCED men, men who can make the decisions necessary to keep the job moving ahead without making big mistakes, are needed on any given fracking job site?
I am not sure there is sufficient frac capacity to ensure modest growth thru 2Q2017. The lag time from POB and RDMO to perforating will increase as more rigs go back to work, for sure. And costs will be going right back to where they were pre 2014. Then more spreads will become available, not until frac prices go up.
In the Permian, where gas to liquids ratios in the production stream start at 30% and begin increasing as soon as those wells are gutted to recover oil, this might become a big time problem: https://btuanalytics.com/permian-gas-takeaway/ The E in the BOE scam might not contribute much, or at all, to Permian economics. Then what happens to shale oil growth? Nothing but a few more dollars have been added on the back side of the profitability equation and these shale wells, wherever they are drilled, are still grossly unprofitable.
Its easy to sit behind a desk and make guesses about the future. You have to understand what’s going on in real life, however…out there in the field, in the rain, in the snow, at 3:00 am in the morning. Most here don’t have a clue.
Mac, think of a large frac as a well orchestrated symphony that literally begins a week before the concert. Somebody has to lead, much like a general is in charge of a battle. The responsibility and stress can be enormous because cost overruns, and landowner issues, all fall on the back of the man in charge. Only 30 different things can go wrong during the frac process; perforation guns must be tracked down the lateral, the well perforated at precisely the correct interval, the right sand concentrations pumped into that specific stage at the right pressures; the stage may screen out prematurely, the man in charge must make a quarter million dollar decision on the fly, in seconds, to shut down pumps, or increase pressure to try and get the stage to take more sand. No two stages frac the same. Then the frac plug above the last stage needs to be set in precisely the right spot and the entire process repeated 40 times. While that is going on fuel, crew changes, sand, water, etc. etc. is being directed all about by 100 different men to ensure the process is completed without interruption and without problems over a week period.
The concert costs 4.5-5.0 million dollars and you want (but seldom receive) it to go off without a hitch. Those guys in charge often earn 2000 dollars a 12 hour day, plus this and that, and they earn every penny of it. Their asses are on the line. I’ve been there, its not easy. You can step outside the frac van to take a leak and in a matter of seconds something bad happens, the casing is ruptured and you have ruined a 7 million dollar well.
Now close your eyes and picture all that occurring… using your own money. Not borrowed money, but YOUR money; money you earned the old fashion way. Nothing to do with the oil business is a game people simply yak about on the internet to pass the time. That stuff that goes on out there in the middle of the night, it’ll make you, or break you in a Midland minute and you better be ready for it either/or.
Hi Mike,
I imagine only those that are very confident in their ability are willing to take those risks. When it works out the rewards are probably worth it or nobody would do it.
I wish you well. Though if you were advising a 25 year old, it is not a business that is likely to last until they are 60, in my view. So better to look for a different industry, for 40 year olds they might as well stick with it.
Dennis you might be right but that’s exactly what dear departed dad told me in 80 when I decided on petroleum engineering. I think we were using 55 mm a day then.
HH
Brook
After this bust, I do not know why a bright young person would go into the upstream oil and gas sector. Think of all the young people who went into Petroleum Engineering in 2010-2014, hoping to come out with a high paying job.
There is a draw to it, no doubt, but better have your eyes wide open. Never thought I would see $19 posted in our basin, but it did happen more than once this year.
I wonder how many people got out during this bust?
Hi Mike, you do a great job of pointing out just how tough a job the BOSS has. I certainly could never handle that level of stress myself.
But you didn’t quite answer my question. HOW many men right on site, during those hours the frack is coming off, need to be well seasoned pros, as opposed to reliable guys who will do what they are told instantly, and know how to do it?
How many men are on the actual job site, during actual fracking operations ?
My guess is that when times are good for them, most of them are making a hundred a year, with supervisors and senior mechanics making a lot more.
A hundred men making top trades money still doesn’t total up to but a very minor fraction of five million bucks in the course of only one week.
This is why I think operators will be able to hire crews, they can steal the men back from where ever they went when they were laid off.
Been there and back again a couple of times myself, in the trades, but never on an oil field job.
The key is to have a very well written procedure, and to go over the job in detail before it starts. I also like to make sure I’m up between midnight and 6 am, because that’s when accidents happen. Lots of coffee is also important. Never let a person with a cold into the job site. The rookie should wear a yellow hat to make sure people keep an eye out for mistakes.
Hi AlexS,
When I suggest th EIA is optimistic, I mean the longer term forecast out to 2030, I agree 2017 in the STEO looks reasonable (or perhaps a little too conservative. It is 2022 to 2030 in the AEO 2016 that looks too optimistic in my view.
Dennis,
Guy Minton’s post referred to EIA’s projections for 2017.
The chart below (that I had posted a couple of weeks ago) shows that the EIA has been constantly underestimating resilience of the U.S. oil production (particularly, LTO), and therefore had to make upward revisions. In my view, if oil prices in 2017 stay around $55 levels, the EIA’s forecast for next year is still too conservative.
Production in the GoM is a special case, as it depends on project start-ups.
As regards longer-term forecasts, there are too many unknowns, which include both resource availability and future economics of LTO.
Lower 48 states (excl. GoM) C+C production projections from the EIA STEO, January-December 2016 issues
Hi AlexS,
I didn’t read carefully. I agree with you the EIA’s short term predictions have been too low and output has been more resilient than many (including me) imagined. The AEO 2016 C+C estimates after 2020 don’t look reasonable to me, chart below in quadrillion BTU per year.
On resource estimates, I also agree there are too many unknowns to do a great forecast, but the EIA is too optimistic about resource availability in the long term, the forecasts of David Hughes are much better and USGS resource estimates are much more reasonable than EIA estimates.
I base my guesses on the TRR estimates of the USGS and reasonable future price and cost scenarios. For US LTO the URR will be between 30 and 40 Gb at most (18 Gb from Bakken and Eagle Ford, 15 Gb from Permian, and maybe 5 Gb from everywhere else in the US). That guess is optimistic, it could well be less than 25 Gb.
Hmm. I don’t know about those 2020-2025 numbers, but by 2025 disruption from electric cars will be sufficiently evident that I expect capital for oil to dry up.
Dennis,
The EIA will soon release AEO 2017.
Will be interesting to see how they have changed their long-term oil production forecast.
Several months later they should release their assumptions with oil resources estimates.
As regards USGS vs EIA TRR estimates, we had recently discussed USGS estimate for Wolfcamp (20 GB), which was much larger than the EIA’s numbers. USGS estimate for the Bakken and Eagle Ford were made several years ago; and who knows what will be their updated numbers.
AEO 2016 U.S. C+C Output Projections (mb/d)
Hi Alex S,
That looks like roughly 5 Mb/d for 25 years for LTO (average per year) which would be about 45 Gb over 25 years. I don’t buy it.
About 4 Gb has been produced already and I expect total URR to be about 40 Gb at most for US L48. Most people think I am far too optimistic on LTO, and I think 30 Gb is a more reasonable estimate (possibly also too high, but that’s my current best guess).
Note that the range of the USGS estimate is very wide 11 Gb to 30 Gb. I think 15 Gb may be a possibility for the entire Permian LTO URR, 20 Gb seems high. The median estimate (F50) for UTRR is 19 Gb.
“That looks like roughly 5 Mb/d for 25 years for LTO (average per year) which would be about 45 Gb over 25 years.”
57 Gb over 2014-2040.
LTO output exceeds 5 mb/d in 2020; 6 mb/d in 2029 and 7 mb/d in 2040.
Hi Alex S,
Is 57 Gb LTO only, or all US L48 C+C from 2014-2040?
LTO only
Thanks Alex.
I would call that very optimistic, bordering on absurd.
Yes, absurd.
There is a fine gentleman that posts on Enno’s site occasionally that would refer to much of the EIA’s LTO estimates as P4 reserves. That is, proven, probable, possible and power point. Much of the 1.2M BOE EUR’s now coming out of the Permian are P4 reserves.
In AEO 2015, the EIA estimated cumulative U.S. LTO production over the same 2014-2040 period at 48 Gb.
Technically Recoverable Resources of LTO were estimated at 78.2 Gb.
In AEO 2016, estimated TRR of LTO were not disclosed, but at least the number for the Bakken was unchanged. Yet, cumulative output forecast for 2014-2040 was increased to 57 Gb.
“Declining well economics translates to higher breakeven prices for shale producers.”
Merger’s like GE – BH may help to firm up the bleeding in Services? no?
http://seekingalpha.com/article/4032390-something-pricey-way-comes-oil-breakeven-prices-rise
https://www.zacks.com/stock/news/237066/merger-madness-continues-with-ge-baker-hughes-oil-deal
Long timber.
I note in the comments section in the Seeking Alpha article a statement from a private non-operating interest owner that “PowerPoint” costs of new wells are not real in the shale plays, AFE’s are for $12 million per well in their particular play, with company touting $7 million in investor presentations.
We will rarely ever see the well payout statements. Access to all of them would be like pulling a bottom card from the house of cards.
SEC?? Why not?
Caveat Emptor
also
There’s a Sucker Born Every Minute
The SEC has been off the job since the early 2000s. I figured this out before most investors did, and knew how to deal with it, because I learned my investing at the knee of my grandmother… who invested in the 1920s when there was no SEC.
Mexico production is down 23,000 bpd (1%) October to November; 8.1% drop y-o-y (up from 7.8%). Oil rigs are down two.
George,
These numbers are for C+C+NGLs.
C+C production was 2,072 kb/d, down 31 kb/d from October 2016; and -9% vs. November 2016.
Average C+C production in January-November was 2,164 kb/d, a 4.5% y-o-y decline.
Mexico C+C+NGLs production, 2014-16
Mexico C+C production by key source (mb/d)
source: Pemex presentation
The decline in Cantarell is stunning!
Based on PEMEX’ recently updated business and strategy plan, Mexican C+C output is projected to decline by 186 kb/d (-8.7%) to 1,944 kb/d in 2017. This follows a 137 kb/d (-6.0%) decline expected this year.
In accordance with the OPEC-NOPEC deal, Mexico has agreed to cut output by 100 kb/d in the first half of 2017.
Given that October 2016 reference C+C production was 2,103 kb/d, 1H17 production should be 2,003 kb/d.
Thus, it is clear that Mexico’s contribution to the cut will be the result of “managed natural decline”.
Baker Hughes rig count: oil rigs + 13; gas rigs +3
Oil rigs only:
Permian +4
Cana Woodford +2
Eagle Ford, Bakken, Niobrara: +1 each
Permian now accounts for half of U.S. oil rig count. The number of oil rigs there has almost doubled (+98.5%) from late April lows.
Oil rig count in 2016: Permian basin vs. rest of U.S.
Eagle Ford: 50% growth from lows;
Bakken: +45.5%, although growth has stalled since early November. I think this is due to significant price differentials between Bakken wellhead oil prices and WTI.
Relatively modest growth in Cana Woodford (+46%), but oil rig count there is only slightly below Eagle Ford and above Bakken.
Sharp growth in Niobrara (+108%) and Granite Wash (6.5 x)
Oil rig count in 5 basins (ex Permian)
Hi AlexS,
What percentage of the Permian rigs are vertical rigs?
Dennis,
215 out of 262 oil-directed rigs in the Permian are horizontal (82%).
It is interesting that the share of horizontal rigs was 86-88% in April-July and has slightly declined since then as the number of vertical rigs was recovering more rapidly in the second half of the year.
There is no rigs drilling for gas in the Permian now.
Oil rig count in the Permian basin
source: Baker Hughes
Thanks Alex.
Looks like it’s mostly LTO, I know in the past there were a lot of vertical wells being drilled, I wasn’t sure if there had been a return to that.
vertical wells went from 15 in late April to 43 now. There is now more vertical wells in the Permian than total wells in any other U.S. basin. There is still significant conventional oil production in the Permian. And in the past LTO was also produced with vertical wells in some parts of the Permian.
Alex
The Bakken folks have an added incentive to wait for DAPL access this coming spring.
If a very odd comment made on another site is true, a lot of folks may be in for a surprise.
An individual, claiming to be a local from the area, said the drilling under the lake is not only completed (it was done from the east side, he said), the inner pipeline was already pulled through and the outer pipeline (there is a pipe within a pipe going under the water) was in the process of being installed.
Kinda weird sounding, but in a few weeks time we may get to see if it’s true.
coffeeguyzz,
this is indeed a quite plausible explanation. Thanks.
coffeeguyzz,
That caught my eye too; it was posted at OilPro. It disappeared a day or so later, and a query why from another poster received no reply.
We live in a world of mystery. Better than a boring one.
Happy Christmas.
That comment is bassakwards, it’s not likely they would run an inner pipe first and then run an outer pipe. The guy may have meant they drilled the hole, the pipe poked through the surface, and they pulled the liner back using the drill string. The pipeline goes inside the hole liner, or casing if you want to call it that. But I don’t see them pulling a pipeline and then pulling an outer string. It doesn’t make any sense.
Off topic but here’s a Christmas present for everybody, excepting hard core Trump fans. None of that sort hang out here any way, with maybe one or two exceptions who comment only at long intervals.
Go to quora dot com, and and enter Trump jokes in the search box.
I guarantee ya all a number of belly laughs.
Merry Christmas, and hopefully a happy and prosperous new year coming up!
OFM – More than one or two – We just do not whine as much about politics as you guys do.
Hi Clueless,
There are some really good Clinton jokes there as well, not to mention a bunch about BOTH Clinton and Trump , as a pair.
Happy New Year!
Plenty of Trump supporters around America and the world for that matter. Especially those that don’t deem the Russians as the scary boogeyman.
The Russians arent the scary bogeyman. I’m hoping trump will defeat the warmongers and make a deal with Russia. They can be a key ally.
Reservoir Damages May Stop OPEC From Cheating
OPEC oil production comes primarily from conventional reservoirs. These reservoirs require reservoir pressure management. Some have suggested that Saudi Arabia’s rationale for cutting production was to reverse the reservoir damage that overproduction has, or may have, caused. Preservation of reservoir integrity may ultimately limit “immediate” increases to inventories from OPEC.
Okay, will someone please tell me how Saudi Arabia could have any “spare capacity” at all if their reservoirs have been damaged from overproduction? If they are overproducing their reservoirs now, then to produce even more “spare capacity”, they would have to over-overproduce those reservoirs. That would be an absurd proposal.
Every OPEC nation is now producing at absolute maximum capacity. With the exception of the two countries, Libya and Nigeria, that have political production problems, they are all overproducing their reservoirs. They are doing this so when they are “forced” by OPEC to cut production, they can just cut back to normal production.
People who still talk about “OPEC spare capacity” haven’t a clue as to what the hell they are talking about.
Aramco IPO May Not Reveal Oil Reserves
December 20, 2016
http://www.energyintel.com/pages/worldopinionarticle.aspx?DocID=946738
One of the biggest obstacles to Saudi Arabia’s planned initial public offering (IPO) for state oil giant Saudi Aramco has been the sensitive requirement to subject Saudi oil reserves to public regulatory scrutiny. But in an unconventional move, Riyadh is considering an approach to exclude reserves from any formal accounting of Aramco’s assets, according to Petroleum Intelligence Weekly. Instead, it wants to value the company based on financial returns from production over a period of years or decades. While this approach risks lowering the valuation of the company and limiting the foreign exchanges where it could have a listing, it has the advantage of preserving an important state secret. The argument for this approach is that the state owns the reserves, not Saudi Aramco, which is the monopoly producer.
……………………………………….
The reserves issue was always going to be thorny, and the current thinking is to derive the value of the IPO from the value created from each barrel produced, based on a revised tax and royalty scheme that the company has been working on for months, according to Saudi industry sources. Investors will be presented with details about Aramco’s 12 million barrel per day production capacity, which for the time being will not be expanded, its average yearly production and profit per barrel — or “economic rent.” Aramco will only provide the unaudited 261 billion barrels of reserves that it publishes in its annual reports, and uses in a bond prospectus, as it did in October.
The justification for this unusual approach to the IPO is that Aramco does not own the reserves, the state does. And while Aramco has a monopoly to produce those barrels, it does not have the right to reveal what are the kingdom’s most important assets and a closely guarded secret. Inevitably, a decision to avoid vetting reserves will reinforce suspicions by those that already think Saudi Arabia has something to hide.
Inevitably, a decision to avoid vetting reserves will reinforce suspicions by those that already think Saudi Arabia has something to hide.
Why don’t they tell us something that we didn’t already know.
Oh my. Do you think anyone is going to actually *buy* those Aramco shares? And how big of a sucker will they be?
The logic is baloney. To get around it they could create an Aramco subsidiary with 30 year license rights to a field which they regulate to have its production held at say 500,000 BOPD. They can sell the subsidiary shares with a fully audited reserve estimate equal to 500kbopd*365 days per year*30 years. The auditor only has to certify the field has the oomph to keep producing that amount for 30 years.
This is just an example. In this particular case the buyer will see less reserve risk and worry more about OPEX. If the Aramco sub has a PSA contract with a stabilization clause like say in Angola, and the terms are decent, it will sell. The sale doesn’t have to be in a stock market, they can simply put it up for auction, allow consortia of up to four companies each to bid.
I get the impression they are a bit amateur about how to get this done.
The auditor only has to certify the field has the oomph to keep producing that amount for 30 years.
Oh my goodness. The auditor still has to certify the field and say it can keep producing for 30 years. Do you really think that Aramco, or an Aramco subsidy, which is still Aramco, would allow an auditor to look at the field data? They would have to in order to certify anything. That is exactly what Aramco will not do.
The sale doesn’t have to be in a stock market, they can simply put it up for auction, allow consortia of up to four companies each to bid.
Of course it doesn’t have to be on a licensed stock market. They can sell chunks of anything to anyone without disclosing a damn thing. It would just be a private sale. But that company that buys the chunk of Aramco, could not itself be a public company with stock on stock exchanges. That would be a severe limitation. They are talking many billions of dollars here. And there is only one place that much money is available. And that place is the open market where millions of people buy a small chunk of it. And that requires disclosure.
I get the impression they are a bit amateur about how to get this done.
Aramco is not so stupid as you assume. They know what they don’t know. And they know that money can hire the best advisers in the business. They would tell these advisers, the smartest advisers that money could buy, to tell them how to get around the requirement that all assets must disclosed in order to list these assets, as part of a public offering, on a stock exchange.
And of course those experts would tell them that this just cannot be done.
In other words, they have no chance to sell a big stake in Aramco at a good price.
Probably, that was one of the reasons KSA accepted the output cut deal.
Well there is no doubt that KSA had a plan in mind. They wanted the option to sell the shares at a high price and buy them back at a lower price. Of course they could do this if they controlled the news of the company’s welfare. They could sell then disclose some serious problems with the company, causing the price to crash, then buy back at a much lower price.
I really don’t think that plan will pan out however.
I suspect there’s some stock exchange with lax rules for listing which will let them list it as a public offering. Probably not London or New York, but somewhere…
Maybe Venezuela or Liberia. I think that it would be a very successful offering.
Aramco isn’t calling the shots. My impression is they got a retard prince in charge and the guy is botching everything.
My outline spells out how they can get cash for floating a company which owns a single field for a limited time span (30 years) and have reserves certified as I described. How do I know? Because I have done it. I guess this is a bit too subtle for some people to grasp it.
Fernando – An “auditor” [as that term is commonly used to describe the accountants] will NOT certify the potential production from a field. They will certify that the company “obtained a report signed off by reputable qualified reservoir engineers” that validates the numerical calculation.
If it turns out not to be true, the reservoir engineers are at fault. Only if the accountants accepted a report from obviously fraudulent sources would the auditors be at fault.
Clueless, I’ve booked giant reserves for a multinational. The reservoir certification isn’t done by accountants. It’s done by petroleum engineers with the appropriate background and certification. The full package in a case like this includes an outline of the contract terms (30 years) an approved development plan, and other items. In some fields we establish full capacity times an operational efficiency, book that as proved plus probable, book sec proved, book for host country using their rules, and present an outline of cash flow for the proved plus probable, explaining the probable will become proved as the wells are drilled. This is made into a presentation for investors, and the shares sell like hot cakes. As a matter of fact it’s not really necessary to sell public shares, private investors go nuts over these deals.
Saudi Arabia produced about 160-170 billion barrels in total.
Since 1988, when Saudi Arabia revised their reserves from 169.6 to 255.0 billion barrels, they produced about 100 billion barrels and maintained their reserves at about 263 billion barrels on average. So if their estimate of 1987 was right, they produced nearly 70% of their initial reserves and should be now in decrease. If their new estimate of 1988 was right, they should have produced around 50% of their initial reserves.
Let’s say this latter hypothesis is correct, it is really time for them to sell Saudi Aramco before everybody see what we all know on this blog.
They probably peaked using “traditional” oil extraction in 2004-2005, then used all the new techniques to push the production up and are now reaching the final limit.
I am looking forward to see what will happen in the next few years.
Rystad Energy estimate of Saudi Arabia’s 1P reserves is only 70 billion barrels, almost 4 times smaller than official estimate.
http://www.rystadenergy.com/NewsEvents/PressReleases/united-states-now-holds-more-oil-reserves-than-saudi-arabia
Thanks Alex,
the 2PC number corresponds approximately to the new estimate of SA back in 1988 less production since then if we take into account some new discoveries. So they should be at around 50% of their initial reservoir or slightly more.
Rystad doesn’t expect Saudi oil production to exceed current levels of slightly more than 10 mb/d.
By contrast, they expect significant increases in Iraq and Iran, with total output in the Middle East rising from 26 mb/d in 2015 to 30 mb/d in 2020
http://www.rystadenergy.com/NewsEvents/PressReleases/middle-east
The Aramco sale was an idea pushed through by Mohammad bin Salman Al Saud, who has been variously described as “… a political gambler who is destabilising the Arab world …”, “The most dangerous man in the world?”, “… aggressive and ambitious …” and ” … Naive, arrogant … playing with fire.” There may not have been much business logic behind the original plan, just him proving a point. He seems to have gone off the radar since October as well.
KSA has a clear economic incentive to cut output:
Goldman Sachs raises 2017 oil price forecast on compliance rethink
London (Platts)–16 Dec 2016 842 am EST/1342 GMT
http://www.platts.com/latest-news/oil/london/goldman-sachs-raises-2017-oil-price-forecast-26622256
Goldman Sachs raised Friday its oil price forecasts for 2017 after reassessing the likelihood that key global oil producers, led by Saudi Arabia, will stick to output cut pledges under OPEC’s efforts to clear the oil market glut.
After analyzing Saudi Arabia’s fiscal revenue outlook for 2017, the bank said it sees the motivation for an average 84% compliance with the announced collective OPEC and non-OPEC production cuts which it estimates at a total 1.6 million b/d.
“Ultimately, our work on Saudi Arabia’s fiscal balance suggests that the kingdom has a strong incentive to cut production to achieve a normalization of inventories, even if it requires a larger unilateral cut, consistent with comments last weekend by the energy minister,” Goldman said in a note.
Saudi energy minister Khalid al-Falih on Saturday said his country was prepared to slash production below 10 million b/d, after having previously agreed to cut down to 10.058 million b/d.
Saudi 2017 budget projects 46% rise in oil revenues, no details on fuel price hikes
London (Platts)–22 Dec 2016
http://www.platts.com/latest-news/oil/london/saudi-2017-budget-projects-46-rise-in-oil-revenues-21425903
Saudi Arabia expects to earn 46% more from oil revenues in 2017 compared to this year, with expectations of rising global demand combining with the OPEC-led global production cut to push prices higher.
In its annual budget unveiled Thursday, the kingdom said its oil revenues were projected to hit Riyals 480 billion ($128 billion) next year, up from Riyals 328 billion ($88 billion).
The budget did not reveal any details about Saudi Arabia’s oil production plans or targets, nor does it say what price it expects to receive for its oil, though it cited the International Monetary Fund’s estimate of 2017 oil prices at $50.60/b. Oil prices in 2016 averaged $43/b, the budget document said.
Overall revenues for 2017, including non-oil revenues, are expected to rise 31% from 2016 levels to Riyals 692 billion.
With the budget laying out an expenditure plan for Riyals 890 billion ($237 billion), an 8% increase over this year, this means the kingdom will be facing a deficit of 198 billion riyals ($53 billion), down 33% from this year, as Saudi Arabia has had to tap into its reserves to withstand the low oil price environment of the last two years.
“The 2017 budget was prepared in light of developments in the local and global economy, including the estimated price of oil,” the budget document states, attributing the increases in projected revenues and expenditures to energy pricing reforms.
“As the kingdom’s economy is strongly connected to oil, the decrease in oil prices over the past two years has led to a significant deficit in the government’s budget and has impacted the kingdom’s credit rating.”
Total national debt for 2016 was about Riyals 316.5 billion ($84 billion), or 12.3% of projected GDP.
My estimate continues to be $63 per barrel Brent.
Essentially this is very close to BofA Merrill Lynch price prediction. Does not promise great profitability for shale ;-).
This price might increase the chance of Seneca Cliff.
And does not save KAS from its huge budget deficit (Platt thinks that they need at least $85 to balance the budget). Russia probably can balance budget at this price (anything about $55 average will suit)
See http://oilprice.com/Energy/Energy-General/The-Craziest-Oil-Price-Predictions-For-201712879.html
$63 is also simply too high — it translates to gasoline prices which are high enough that electric cars are substantially cheaper to operate. Purchase price parity for electric cars is coming next year for the midmarket, probably 2019 or 2020 for the downmarket.
Saudis Plan to Sell 49% of Aramco in 10 Years
A 49% stake will be sold within 10 years, according to al-Eqtisadiah, the Riyadh-based newspaper, which cites an unidentified senior government official, Bloomberg reported.
I don’t understand why the Saudis are trying to sell a profitable entity like Aramco? How is short term cash going to help them over the long term?
I think they want to sell investors a pup.
It might be that Aramco will be less profitable in the future, or they know their peak oil production is now and want a lot of money now to prepare the transition. They would avoid having a huge debt.
Yep. Pawn Aramco off to suckers before it becomes worthless. (It becomes worthless circa 2030 on demand-based projections.)
It’ll be interesting to see whether this attempt works or not.
I think, in the near term KSA will be able to sell a relatively small stake in Aramco to locals and citizens of other Gulf countries. That will not require disclosure of audited reserves number.
Another option is selling non-upstream subsidiaries.
Suppose . . . Neither oil consumption (nor demand) nor oil production changes, but the dollar’s value does.
Yes, go ahead and ask relative to what. The Euro? Nope. The yen? Nope.
I almost don’t need to go further because just revisiting the failure of that yardstick suffices — but if you insist, or even if you don’t, well, KSA can hit their oil revenue target and deficit erosion target by declaring the value of their oil flow in their currency to be whatever they like. Why care about the price of Brent when it need not be relevant?
http://finance.yahoo.com/news/bonanza-creek-other-u-energy-162825818.html
“Bonanza Creek Energy Inc and two other energy firms announced on Friday plans to file for bankruptcy in coming weeks, joining a long list of U.S. energy companies that have succumbed to a drop in oil prices.”
…
“As of Dec. 14, 114 oil and gas producers had filed for bankruptcy in 2016 with $57 billion in total debt, more than double the number of filings in 2015, …”
…
“Among companies … that provide well-site services to energy exploration firms, 110 had filed for Chapter 11 protection with $17 billion of debt as of Dec. 14, also more than double the 2015 number, according to Haynes & Boone.”
224 total companies, $74 billion total debt – whoo whee, sounds like a lot of write downs…
Dakota Plains Holdings Begins Voluntary Chapter 11 Proceeding
December 22, 2016
http://www.ogfj.com/articles/2016/12/dakota-plains-holdings-begins-voluntary-chapter-11-proceeding.html
Dakota Plains Holdings Inc. (NYSE MKT: DAKP) and six of its wholly owned subsidiaries filed voluntary Chapter 11 petitions in the United States Bankruptcy Court for the District of Minnesota on Tuesday, December 20, 2016, initiating a process intended to preserve value and accommodate an eventual going-concern sale of Dakota Plains’ business operations.
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Dakota Plains Holdings Inc. is an integrated midstream energy company operating the Pioneer Terminal transloading facility. The Pioneer Terminal is centrally located in Mountrail County, North Dakota, for Bakken and Three Forks related Energy & Production activity.
Does anyone here know if there is an industry standard with regard to profit margin for upstream oil and gas service companies?
In other words, what does a service company strive for in terms of the amount of sales in excess of the cost of services?
I have found that in 2016, the sales barely exceed cost of services, and in some cases are slightly less than the cost of services, for service companies I have reviewed through Q3.
All have lost money, after subtracting G & A, R & D, D, D &A and interest expenses.
So, if someone can give me a ballpark, I could go back in and try to figure how much service costs are going to go up from here.
I did read in one 10Q where a frac company has about half of its frac equipment idle. They feel they can rehire personnel and get the idle equipment back on within 60-90 days.
Shallow Sand,
This is a questionable exercise. Like French said “The appetite comes during a meal.” So I suspect that the level of profitability they strive at, say, $60 per barrel is different from what they strive at $50.
They are watching closely profitability of wells and their prices greatly depend on this factor.
So at $70 and $80 it will also be different. There will be price inflation in this sector, no question about it.
In no way they will leave “too much” dollars on the table for guys who so unceremonially pushed them over the red line in the past. And they do have almost exact information about the level of profitability of their clients.
What is clear that they greatly suffered from the current “cutting to the bone” mode. And that means the current rates will be increased as soon as oil prices increase to, say, over $60, where shale operators have positive cash flow on their best wells. I remember that somebody here posted an average shale well needs probably around $70–95 per barrel to make economic sense, but for best wells in sweet spots it is definitely lower then that.
BTW 1 Mb/d is 160,000 m3/d. This looks is a like medium gas and rocks volcano output during eruption ;-). Bigger have output over 300,000 metric tons a day (like one in Iceland) which is close to 2 mb/day oil extraction rate.
https://biz.yahoo.com/p/sum_conameu.html
The EIA’s Monthly Energy Review did not have data for November but has October oil production down 67,000 bpd and down 1,114,000 bpd since peaking in April 2015. That peak was 9.627,000 bpd and stood at 8,513,000 in October.
Just 2 weeks before the release of Monthly Energy Review, in the Short Term Energy Outlook, the EIA had estimated U.S. C+C production in October at 8,703 kb/d.
This represented an increase of 123 kb/d over September data vs. a drop of 67 kb/d in the MER.
The difference between the STEO and MER estimates for October is 190 kb/d, quite significant.
(The numbers for previous months are the same).
I guess the key difference is in the number for the GoM, where the STEO was projecting growth of
154 kb/d from September to October.
In any case, both MER and STEO estimates for October are preliminary.
More or less reliable data for that month should appear in Petroleum Supply Monthly scheduled for release on December 30.
US C+C production: EIA Monthly Energy Review vs. Short-Term Energy Outlook
Well the Petroleum Supply Monthly will be out Friday. We will see what they have to say. They are usually the most accurate of all.
India might be following China, Colombia and Mexico into high decline rates. They are 2.6% from October to November and 5.4% down y-o-y. They have a 75,000 bpd project under development for 2020 start up but most of the talk has been about natural gas rather than oil. Their onshore fields are old and some are very waxy, so need a lot of care and attention.
Oman and Malaysia have agreed to cut as part of the OPEC deal but I think they are at or close to turning over to higher natural decline rates anyway, though Malaysia has a new Shell project starting up. I think Vietnam, Australia and Ecuador are other medium sized produced now in accelerating decline (although I’ve been saying that for Ecuador for 18 months and they continue to hold a plateau).
This shows India production and rig count.
George,
Here are some data for a few of the countries you mentioned in your post:
Oil Production Data for Selected Countries
Crude Oil + Condensate (Milion Barrels/Day [mb/d])
Country/State …………A* …..B*……………..C*……………D*
Argentina ………1998-Q2 ……..0.858 ………0.526 ……..38.7
Australia ……..2000-Q1 ……..0.742 ………0.299 ……..59.7
China …………….2015-Q2 ……..4.312 ………4.130 ……..4.22
Egypt …………….1996-Q4 ……..0.927 ………0.497 ……..46.4
India …………….2010-Q4 …….0.802 ………0.737 ……..8.10
Indonesia ………..1991 ……………1.592 ………0.834 ……..47.6
Malaysia ………2004-Q4 ……..0.775 ……….0.677 ……..12.6
Mexico …………….2005-Q2 ……..3.519 ……….2.264 ……..35.7
Norway …………….2000-Q4 ……..3.325 ………..1.654 ……..50.3
U.K. …………….1998-Q3 ……..2.753 ……….0.999 ……..63.7
Alaska ……………..1988 ……………2.017 0.483 (2015) ……..76.1
A* – Peak Production Year/Quarter
B* – Peak Production (mb/d)
C* – Production Quarter 1 of 2016
D* – Percent Decline from Peak
Data from the US DOE/EIA
Many of the above countries/state have been in long-term decline and weren’t significantly reversed by high oil prices.
Small World – Max and Stacy in Pensacola talking Markets, Fast Cars AND Peak Oil…
https://www.rt.com/shows/keiser-report/371897-episode-max-keiser-1011/
I’ve a new post on gas production in Pennsylvania, here.
Now 79 Bcf below the five year average. http://ir.eia.gov/ngs/ngs.html
The below article seems slightly crazy…. shale oil is still loosing money, but banks are willing to lend more now
http://oilprice.com/Energy/Energy-General/Shale-Spending-Is-Set-To-Soar.html
Okay, look:
“North American oil and gas companies could ratchet up spending by as much as 30 percent, according to Raymond James.”
Raymond James is a brokerage house/investment advisory. “Could”. If you look hard enough you can find an investment house that will say spending could drop 10%. Or raise 50%. It’s all bullshit. They have no idea of anything.
Absolute utter consensus was 3-4 Fed rate hikes in 2016. There was 1. It’s all bullshit. They have no idea of anything. And you would surely think a Fed rate hike total would be more confidently known than oil drilling spending. Advisors couldn’t even get that right.
Oilprice.com is ad funded. The world used to be bad news is news, good news is not news. That reverses for ad funded sites. First comment on the article:
C’mon Nick…
You use “Soar” in the title?
“34 oil and gas companies saw their credit lines raised by an average of 5 percent, providing an additional $1.3 billion in lending. That is a dramatic turnaround from the 40 percent reduction in credit witnessed over the past three redetermination periods, stretching back to early 2015.”
So they got back 5% of the 40% they were cut, and that qualifies as “soar” to you?
Another country possibly hitting higher decline rates is Azerbaijan. They agreed to participate in OPEC cuts through “natural decline” and the chart below might indicate why. They had been on a gentle slope down since 2011, mostly because of the West Chirag platform, bought on line in 2014. They have no new oil production in devlopment. Shah Deniz phase II is a gas/condensate field that could add 50 kbpd condensate around 2020. 80% of the oil comes from BP operated fields, I know they have severe limitations with produced water handling and water injection (a lot of the produced water is pumped back offshore for reinjection). There was a plan in 2014 for a new, large on shore produced water treatment system, which would have removed the bottleneck, but that was quickly shelved when oil price collapsed. I think we’ll be seeing more of these sort of dramatic drops as a consequence of development cancellations over the next couple of years. Even if the sudden drop since August is because of maintenance it would almost certainly be aggravated by deferral of preventative maintenance programs and brownfield developments
The rest of their production is from SOCAR – a lot of their stuff is old and falling apart and they have a terrible record for safety and environmental issues, which I think is probably also reflected in their operations and maintenance efficiency.
I got the data from SOCAR site, I think,but not certain, that it includes condensate. They don’t have prod. water numbers, BPs reports might have them.
“They agreed to participate in OPEC cuts through “natural decline”
That’s correct. Azerbaijan pledged to cut 35 kb/d, while expected natural decline next year may be 35-42 kb/d, according to the country’s Energy ministry.
The ministry expects production in 2017 to decline to 800-807 kb/d from 842 kb/d this year (-4.2-5%).
“Even if the sudden drop since August is because of maintenance it would almost certainly be aggravated by deferral of preventative maintenance programs and brownfield developments”
There was a big decline in September due to maintenance, and another one in November.
From the IEA Oil Market Report:
“In Azerbaijan, maintenance at BP’s Deepwater Guneshli platform during September curbed crude output by 65 kb/d compared with a month earlier. At 770 kb/d, production was roughly 100 kb/d below a year earlier and at its lowest level since November 2014. BTC loading schedules, which account for most of Azeri crude exports, suggest output increased in October. Output is expected to fall back again in November, when BP’s Azeri East production platform, which produced an average 71 kb/d in 1H16, undergoes maintenance.”
BPs Stat Review says since Azerbaijan 2010’s peak production
1023K bpd, 919K, 872K, 877K, 849K 841K. Interesting that they increased production during the Apocalypse years of 2008/9. (895K –> 1014K –> 1023K 2008-2010).
Azeri oil consumption down 33% since the 1990s (160K bpd then), but up 40%, and somewhat steadily, since 2010ish (71K bpd then) to about 100K bpd.
Pop 9.6 million, looks steady increase since 2000. About 1/6th US level per capita burn.
Azerbaijan is one of the oldest oil producing regions in the world
Azerbaijan oil production, 1871-2016E (million tons/year)
source: State Statistical Committee of Azerbaijan
“I got the data from SOCAR site, I think, but not certain, that it includes condensate”
Azerbaijan’s State Statistical Committee (annual) numbers include condensate.
They only slightly differ from SOCAR’s data: for some years lower, for others higher.
http://www.stat.gov.az/source/balance_fuel/indexen.php
JODI has both crude and NGL data for Azerbaijan. Combined crude+NGL numbers (in thousand tons) are very close to SOCAR’s data.
BP’s annual data for Azerbaijan, which also include NGLs, are also very close to SOCAR’s and State Statistical Committee’s numbers.
Azerbaijan monthly production statistics (thousand tons/month)
Sources: SOCAR, JODI
BOEM lease production data for October came out yesterday. Contrary to my expectations there wasn’t a big jump in the new fields (i.e. on-line 2015 to 2016) following hurricane disruptions in September (maybe these fields weren’t affected much). Stones ramp up accelerated. Odd Job came on line. Son of Bluto 2 and Dalmation South seem to have gone off line. Phoenix might have shut down for tie-ins for Tornado. Note I added Rigel and Fresian which I didn’t have before (Fresian might be connected with Holstein in some way – I havn’t quite worked it out). The initials after field name refer to the tie back hub: DH – Delta House, TH – Thunder Hawk, JStM – Jack St. Malo.
For some reason the screen image chops off the bottom items in the legend which are Mars-Ursa, Marlin/Holstein, King/Horn Mountain and Phoenix/Tornado.
George,
I think Fresian should be the same as Holstein Deep. Plains drilled the Fresian discovery before McMoran bought out Plains, and then bought out BP at Holstein (and now Anadarko has it all). I would think Fresian would be considered a tieback to Holstein. (I’m glad your showing the tiebacks and host facilities).
Rigel might be another tieback to Delta House. The original Rigel well was drilled in Mississippi Canyon 252 back in the late 90s or so. The block was later released and acquired by BP and was named Macondo. BP’s first well resulted in the catastrophic blowout in 2010. That lease was subsequently released, and then reaquired and a well was safely drilled to the “blown-out” reservoir and, I suspect, the production you have noted is coming from this reservoir.
SLG – thanks, that makes sense. Delta House was reported doing 80,000 bpd at the beginning of the year: Son of Bluto 2, Rigel and Marmalade only give 60,000, so I’ve probably missed something else unless the 80,000 included equivalent gas. LLOG don’t have the most comprehensive or up to date of web sites so it’s difficult to be certain.
Fresian is in blocks GC599 and G643, lease number G35001. Holstein Deep is given in GC643, lease G06894. They could well refer to the same thing with different names from BOEM and the production company.
There may be another explanation for the difference in flows. The Delta House is designed with low (no?) redundancy on rotating equipment so it has lower reliability than most offshore facilities – i.e. 100,000 bpd maximum nameplate but 80,000 bpd average (i.e. 80% availability compared to 95% which is more typically sought). Therefore 80,000 bpd daily peak may only allow 60 to 65,000 bpd monthly average. The low redundancy may explain why some fields could go offline for a long time, for example Son of Bluto 2 at the moment (just a guess). One of the problems with low redundancy design is that you can end up with one single event making the whole system go black for months while the problem is fixed. They probably carry a lot of spares but even so there are lots of ways to mess up large compressors and pumps which take a lot of effort to fix.
The Petroleum Supply Monthly is out. They have US production up 232,000 barrels per day to 8,807,000 bpd in October.
The big gainers were the Gulf of Mexico, up 84,000 bpd, North Dakota, up 72,000 bpd, Alaska up 43,000 bpd and Texas up 23,000 bpd. The big losers were California and Colorado, both down 6,000 bpd.
The 232 kb/d monthly increase is actually not surprising.
Production in the GoM has recovered after the hurricane season, in Alaska – after maintenance;
a sharp increase in North Dakota was already known from NDIC data; and Texas is up thanks to the Permian.
What I cannot understand, is the estimate in Monthly Energy Review. They missed the October number by almost 300 kb/d
I think, in the next STEO the EIA will revise upward its U.S. C+C production projections for 2017. Probably, they will have slightly higher year-average output (vs. 2016) instead of a 180 kb/d decline in December STEO