by SouthLaGeo
The post that follows is a guest post by SouthLaGeo, a geologist with over 30 years of oil industry experience.
In this post, I will address 3 topics relating to the Northern Deepwater Gulf of Mexico –
1. Historical oil production
2. One view of the future of exploration
3. EUR ranges
I will limit my comments to oil production (not gas production). All production data is from BSEE/BOEM. The play outlines on the map are my best estimates. I will be using the BSEE definition of deepwater which includes water depths greater than 1000’. And, I will be assuming a Business As Usual future – by that I mean that fossil fuels will continue to be an important an energy source, and the world will continue to be able to afford them.
1. Historical production
Cumulative production to date from the deepwater GOM is about 7 billion barrels of oil (Bbo). Total shelf production is about 13 Bbo. The chart below shows both shelf (in green) and deepwater production (in brown/red), in annual, increments, going back to 1985. As you can see, shelf production dominated throughout the 80s and 90s, and then in 2000 deepwater production exceeded shelf production, and it has been that way ever since. (The totals above include production from before 1985)
The 3 peaks in deepwater production, in 2002-2004, 2009-2010, and the present peak from 2014, are the results of advances in technologies that have allowed industry to march into deeper water and produce from deeper reservoirs.
The earliest peak was, in a sense, an extension of shelf play types into deepwater. The reservoirs were Pleistocene to Miocene in age, mostly bright-spot associated, and outboard of salt, and ranged in depth from ~10,000-20,000’. The biggest fields in this trend were Shell’s Mars/Ursa complex in Mississippi Canyon, and their Auger field in Garden Banks. Peak production approached 1 million barrels of oil per day (mmbopd).
What is a “bright spot”? Without getting into geophysics too deeply, a bright spot is an anomaly that stands out on seismic data relative to the background, and is often an indicator of an oil or gas accumulation. Google it and you will find some nice examples.
As technology advanced, industry moved in to deeper water and deeper reservoirs. One technology in particular, seismic acquisition and processing, was critical in this regard. The next trend, the subsalt trend, was discovered because of advances in seismic technology.
The Seismic Advantage:
The use of seismic data has always been an important tool for explorationists to identify oil and gas prospects (e.g. the application of bright spot technology to identify oil and gas reservoirs outboard of salt as mentioned above), and this is even more so the case in deepwater where exploration wells are expensive, but seismic data is relatively cheap.
Much of the deepwater Gulf of Mexico is underlain by an allocthonous salt canopy (allocthonous = “out-of-place”, meaning in the salt is currently not in the position within the stratigraphic column where it was deposited. Actually, much of the entire northern Gulf is underlain by allocthonous salt, but, on the shelf and “shallow” deepwater, all of the oil and gas reservoirs are above the allocthonous salt. See stylized cross section below.)
So what’s the big deal that much of the deepwater is underlain by a salt canopy? Well, because of the large acoustic impedance contrast between salt and surrounding sediments, salt severely distorts seismic energy with the result being that it is very difficult to get a good image of the geology below the salt, and it is in these subsalt sediments where the oil and gas may be. The cartoon cross section below illustrates this. With “old seismic data” say pre-1995 or so, the seismic image of a given area in the deepwater would look like the image on the left. You could see down to top of salt, but then had no idea what was going on below that salt. But, as seismic technologies advanced in the 1990s, we could start to see images like those on the right – we could image not only the base of salt, but also potential subsalt seismic events that could create hydrocarbon traps. The cartoon on the right is actually a reasonable representation of Chevron’s Tahiti field in Green Canyon.
The stylized regional cross section below, edited from a cross section originally published by McMoran, shows the geometry of the salt canopy, and how the canopy separates above salt, or supra-salt, basins from subsalt basins. The length of this cross section is about 300 miles. The deepwater subsalt discoveries I’ll be discussing are located in the Middle and Lower Miocene, and Eocene (~Wilcox) formations.
With the advances in seismic technology, and many other technologies as well (drilling, completions, platform fabrication, risers, subsea infrastructure, etc,) industry advanced into deeper water, and was particularly sucessful in finding large oil accumulations in southeast Green Canyon. The next peak in deepwater production came in the 2009-2010 time frame as a number of these fields came on production, especially Tahiti, Atlantis and Shenzi from the southeast Green Canyon trend, and Thunderhorse from Mississippi Canyon (Thunderhorse is just east of Mars/Ursa on the map below.) The initial production from these fields resulted in the biggest year-to-year increase in oil production ever in the deepwater – approximately a 400 kbopd increase between 2008 and 2009. Durings this peak, deepwater production was at record levels of about 1.25 mmbopd.
Unfortunately, many of these fields experienced rapid early production declines, and that, in addition to an overall reduction of deepwater drilling in late 2010 and 2011 as a result of the Macondo drilling moratorium, led to the rapid production declines.
Much has been written over the years in both this forum and TOD about this rapid production decline, particularly in reference to BP’s Thunderhorse field. It would appear to me that Thunderhorse has certainly been a disappointment to BP, but they have continued to develop the field, and have recently instituted a waterflood. The other fields I mentioned above, all from the subsalt Miocene trend in southeast Green Canyon, have been more successful.
We are currently seeing a 3rd peak starting in 2014. While the chart above only goes through 2015, early 2016 data indicates that overall production is approaching record levels, and if one backs out shelf production, it is almost a certainty that we are currently seeing record deepwater production levels of over 1.3 mmbopd. The major factors contributing to this are :
- Redevelopments of a number of existing fields including Mars, Atlantis, and Auger (The successful redevelopment of Atlantis resulted in it being the most prolific oil field in the GOM in 2015 averaging over 100 kbopd)
- Initial production from Wilcox fields such as Great White and Jack/St.Malo
Over 30 years of production have demonstrated that there are definite sweet spots within the deepwater Gulf- most notably, the subsalt Miocene of Southeast Green Canyon, and the greater Mars/Ursa basin (see trend map below). Both of these areas have prodcued over 1 BbO, and both have a lot of future prospectivity and are likely to achieve at least 2 BbO or more in ultimate recovery. Five of the six biggest fields to date are from these trends.
Top 6 Northern GOM Deepwater fields in terms of cumulative oil production:
2. One view of the future of exploration
Over the last few years, the exploration results for industry in the deepwater Gulf of Mexico have been disappointing. In my opinion, 2 factors contribute to this –
- Low oil prices have reduced exploration drilling
- The deepwater Gulf is becoming a fairly mature province
Item # 1 above is hard to debate. Overall deepwater drilling is down, and along with that, exploration drilling is down.
Item #2 above might be debated, but let me explain my reasoning.
15-20 years ago, some prognosticators called the Gulf of Mexico the “Dead Sea” because, in their view, there were no more unexplored areas. (Remember, at that time, virtually all of the production was outboard of salt, and bright-spot associated.) The view was that all of the discoveries of note had been made and all that was left was to produce the existing fields. But just about that time the revolutionary advances in seismic imaging technology mentioned earlier started revealing prospectivity below the extensive shallow salt bodies in many areas of the deep gulf where before, these areas were just viewed as nonprospective. The large subsalt Miocene discoveries of southeast Green Canyon were made and started coming on line, and then, industry ventured into other subsalt provinces discovering the Wilcox trend. These were the years of the “great unveiling”, as more and more salt bodies were properly imaged and found not to be salt massifs that extended to basement, but were salt canopies with prospective subsalt section below.
Consequently, many discoveries were made including subsalt Miocene fields like Thunderhorse and Thunderhorse North, Mad Dog, K2, Atlantis, Tahiti, Shenzi, Heidelberg, Stampede and Big Foot, and Wilcox discoveries like Jack/St.Malo, Shenandoah, Tiber, Guadalupe, Anchor, Leon, Stones, and many more.
In my opinion, the era of the “great unveiling” is past its peak, and in decline. The areas that remain to be “unveiled” are those where the salt tectonics are often very complex and where prospective section is revealed, it may be below 30,000’, and sometimes even below 35000’.
This isn’t to say discoveries won’t be made. There will continue to be small basin play discoveries– in the 20-40 mmbo range. The edges of the Inner and Outer Wilcox trends may be expanded a bit resulting in a few 100-200 mmbo discoveries. There also may be some, what I call, one-off discoveries – discoveries that appear to be one of a kind and are not indicative of a new trend (Noble’s recent 40-50 mmbo Katmai discovery in Green Canyon, I think, falls into that category).
Is there a legitimate new play/trend yet to be discovered? For example, is there prospectivity in some formation deeper than the Wilcox, such as the Cretaceous Tuscaloosa? While I’m sure industry is looking into this, they have to realize they would be dealing with reservoirs that would probably have even lower porosity and permeability that the Wilcox, and while industry may be starting to figure out how to produce the Wilcox, the Wilcox reservoirs are very thick, and what they lack in permeability, they can make up in thickness. Note McMoran’s lack of success in establishing production from their deep shelf gas discovery, Davy Jones. We will have to wait and see if industry is able to establish production from deep Tuscaloosa oil – assuming, of course, commercial quantities of Tuscaloosa oil are even discovered.
Some also think there may be a presalt play in the Gulf of Mexico, similar to the successful presalt plays in offshore Angola and Brazil. This is, as far as I know, a completely untested play in the Gulf of Mexico, and, consequently, quite high risk.
(Presalt is not the same as subsalt. The subsalt, as mentioned earlier, is the stratigraphy between the allocthonous, or out-of-place, salt canopy and the autochthonous, or in-place, Jurassic Louann salt. The presalt is that stratigraphy below, or older than, the Louann salt. Note that the Louann salt is not identified on the cross section above. If it were, it would be, for all practical purposes, right above what is labeled Mesozoic.)
One big difference industry will find between the Wilcox and any deeper prospective section is that while the deepwater Wilcox sands are thick, fairly continuous, and present over very large areas of the deepwater (see the trend map above and note the size of the Inner and Outer Wilcox trends, and note that well developed Wilcox sands have been penetrated outside the trends, but commercial oil accumulations have not been discovered, with the exception of the Perdido Fold Belt), other prospective sections will probably be much more localized, possibly more channelized, and also thinner. Consequently, the prospective play outlines will be much smaller. The outline of the Norphlet on the play map above is a good example. (The Norphlet is older than the Wilcox, being Upper Jurassic in age and was deposited immediately on top of the Louann salt. The Wilcox is younger, being Eocene/Paleocene).
Some observers point out how the Gulf of Mexico has continued to re-invent itself over the years. When shelf production started declining off its peak in the late 80s (see initial production chart), some thought that was the end for the Gulf of Mexico. But then, production from the shallow plays of the deepwater started to kick-in (Note that shelf production rebounded at this time also. The peak in shelf production seen in the late 90s was largely due to the introduction of 3D seismic to revitalize shelf fields). Then, as mentioned earlier, when the next decline in production occurred, people started writing off the GOM again as the “Dead Sea”, but then production from the subsalt discoveries, first Miocene fields, and now Wilcox fields, started contributing.
Is there another “reinvention” of the Gulf to be made? Or, when this current peak in production begins to flatten out, will that be the start of terminal decline? Let’s see what the state of GOM exploration is by about 2020? If a legitimate new play has been found by 2020, then I can envision another peak in production (or at least a flattening in the rate of decline) in the late 2020s to early 2030s. If not, then it may be that the current peak will be the final peak.
3. EUR ranges
In this section I will present multiple views on Estimated Ultimate Recovery (EUR) ranges for the Northern Deepwater Gulf of Mexico. I will present Jean Laherrere’s recent estimate, comment on recent resource estimates by BOEM (the Bureau of Ocean Management), and then provide my EUR estimates.
(I came across Jean Laherrere’s document called JL_2016USoilultimate.pdf, where I pulled some displays, it is at the following link:
http://aspofrance.org/files/JL_2016USoilultimate.pdf )
First I will discuss shelf oil production. The chart below is from the 2016 Laherrere presentation where, through the Hubbert Linearization graphing technique (HL), he makes the case for a shelf EUR of around 14 Bbo (Gb). This is, in my opinion, spot on. Current daily shelf production is probably below 200 kbo, activity levels are low, and discoveries are infrequent and small. Even if we had a rapid increase in oil prices and associated shallow water activity, I can’t see EUR getting much higher than 14 BBO, maybe 15 or 16 on the highside.
Before I discuss deepwater EUR, I will look at the EIA’s predictions about near term GOM oil production.
The chart below is monthly GOM production (average daily production per month) from early 2014 through 2017. Every data point left of, and including, the red circled point, is historical data. Every data point to the right is the EIA’s prediction through late 2017. The annual declines in the August through October time frame are their estimates of hurricane related downtime. From the middle of 2015 until May-2016, GOM production has hovered around 1.55-1.6 mmbopd. The EIA estimates that GOM production will start to exceed 1.8 mmbopd in November, 2016, and continue a gradual rise to over 1.9 mmbopd by late 2017.
These seem to me to be rather optimistic estimates. I don’t think production will get to levels over 1.8 mmbopd. 2016-2017 project start-ups that could contribute over 50 kbopd include Heidelberg (in SEGC on play map) and Stones (outer Wilcox). All others will probably contribute less than that. (Remember this is shelf plus deepwater production. Assume about 200 kbopd of the total production is from the shelf, and the remainder is from deepwater.)
I do believe industry will be able to maintain production levels over 1.5 mmbopd beyond 2017 with Stampede and Big Foot (both in SEGC) coming on in 2018. Both of these fields should be able to maintain production levels over 50 kbopd for at least a few years.
Below is Jean Laherrere’s recent HL estimate for deepwater EUR. He gives an EUR of 10 Bbo. His combined shelf and deepwater total is 24 Bbo.
In my opinion, he is underestimating the EUR from deepwater. The 3 spikes in the HL curve tie to the 3 spikes in production discussed earlier – the first spike, at about 1 Bbo, is from the early production from the basin plays, the 2nd spike, at 4-5 Bbo, is from the production spike between 2008 and 2009 from the Miocene subsalt, and the 3rd spike is the current peak in production due to existing field redevelopments and initial production from the Wilcox trend.
I believe Jean is underestimating the significance of the third spike in the way he draws the trend line through the data. It is too early to use HL to predict the EUR from the deepwater. (Jean suggests this in his paper). One has to at least wait until the 3rd spike starts to level off, or decline. When that portion of the curve levels off, or starts to decline, one would predict an EUR significantly higher than 10 Bbo.
While I am by no means an expert on the use of the Hubbert Linearization graphing technique to estimate EUR, I assume it works best in a basin where the biggest discoveries are made rather early, and smaller discoveries follow. And it also works best in basins where, if new plays are found, they are relatively small. That is certainly not the case with the deepwater Gulf of Mexico. (It is the case with the GOM shelf, and that is why HL works fairly well to predict ultimate EUR. That is, the biggest shelf fields were discovered early, and smaller discoveries followed).
If one were only to look at existing fields on production, prior to the 3rd spike in production, I think the 10 Bbo EUR is reasonable, but if one includes the projects that are contributing to the third spike, plus the significant queue of projects that have either just come online, or should come on line between now and 2022 or so, I can see the EUR increasing to 13-16 Gb.
The projects contributing to the 3rd spike, as I mentioned above, include redevelopments of a number of older fields, plus Great White, the first Wilcox producing field.
Many of the projects that have either just come online, or should come online between now and 2022 or so include (including reference to trend map above):
Heidelberg, Big Foot, Stampede, and Mad Dog 2 – from Southeast Green Canyon,
Julia and Stones – from the Outer Wilcox trend,
Appomattox and offsets – from the Norphlet,
Power Nap, Vito and Kaikias from the Mars-Ursa basin
and Tornado, Kodiak and Gunflint – from the basin play trends. (Kodiak is technically not a basin play field, but a subsalt field in Mississippi Canyon).
Then if you include the list of Wilcox discoveries that have been made, and probably will come online in the early to mid-2020s, including:
the Tigress complex (Guadalupe, Tiber and Gibson), Shenandoah, North Platte, Anchor from the Inner Wilcox trend, and
Leon, Sicily and Kaskida, from the Outer Wilcox trend, one can probably add another 2-4 Gb of ultimate recovery.
In the lists above, most of the projects that are highlighted bold will have a producing platform. Other projects will probably be sub-sea tiebacks to other producing platforms. In general, the projects with a producing platform need to be expected to produce at least 150 mmbo to justify the investment – although this number could be debated. The reserves needed to justify a tieback can range widely from as little as 15-20 mmbo for a single well to over 100 mmbo for a multi-well development. The currently producing Caesar-Tonga field in Southeast Green Canyon is a good example of a multi-well subsea tieback field that should easily produce over 100 mmbo.
Next we will look at data recently provided by BOEM. What BOEM provides is actually an endowment estimate, though, I will attempt to determine an EUR estimate from their numbers.
BOEM recently released their “Assessment of Undiscovered Oil and Gas Resources of the Nation’s Outer Continental Shelf, 2016”.
http://www.boem.gov/National-Assessment-2016/
This study is effective as of January 1, 2014.
Their total endowment for the Gulf of Mexico is 83 Bbo. This is made up of Cum. Production = 19 Bbo, Remaining Reserves = 4 Bbo, Contingent Resources = 3 Bbo, Reserves Appreciation = 9 Bbo, and Undiscovered Technically Recoverable Resources (UTRR) = 48 Bbo.
The sum of cum production + remaining reserves + reserve appreciation = 32 Bbo. This could be thought of as an EUR estimate from existing fields and be compared to Jean Laherrere’s shelf + deepwater EUR of 24 Bbo. The difference is, I believe, mainly due to BOEM’s 9 Bbo estimate of reserves appreciation – otherwise the totals are 24 v. 23 Bbo. Reserves appreciation is a bottom’s up (field by field) calculation performed by BOEM that results in an “increase in reserve estimates from extension, revision, improved recovery or new reservoirs”.
The remaining BOEM estimate includes 51 Bbo of resources – 3 Bbo coming from existing fields and 48 Bbo from undiscovered fields (BOEM’s UTRR). Their UTRR estimate assumes no economic constraints. When they apply economic constraints, this number varies from 31 Bbo at $30 oil up to 45 Bbo at $160 oil, and the term becomes Undiscovered Economically Recoverable Resources (UERR).
This estimate, whether one uses 31 Bbo, 45 Bbo or 48 Bbo, is quite large, but, keep in mind this is an unrisked resource estimate. In previous comments in this forum, myself and others have commented on these numbers from BOEM’s 2011 report suggesting they are unreasonably high. I was mistaken in assuming these numbers where BOEM’s estimate of EUR coming from undiscovered fields. In actuality, these are resource numbers, not reserves, and therefore they should be risked. Should one risk these numbers at 10%, 25%, 40%?
For a number of years, when what I called the “great unveiling” was occurring, and many of the subsalt basins were being illuminated by new seismic, industry’s discovery rates were probably 30-50%. But, I believe future discovery rates will be lower as more challenging areas are explored. I can see future discovery rates in the 20-30% range.
If one assumes a 25% future discovery rate and applies it to a UERR of 40 Bbo, one gets an EUR from yet to be discovered fields of 10 Bbo (and let’s assume all that comes from deepwater).
So, in total, I estimate BOEM’s EUR total to be 32 Bbo (their cumulative-to-date plus reserves) + 10 Bbo (from new fields) or 42 Bbo. If one assumes a shelf EUR of 15 Bbo, that leave a deepwater EUR of 27 Bbo.
(Please note – BOEM has not provided an EUR estimate for the GOM. I have played some games with their resources estimates, and added these numbers to their cumulative production and reserves estimates to give one view of how BOEM’s numbers could be interpreted to provide an EUR estimate.)
Next I provide my estimate of deepwater GOM EUR. I have previously discussed many of the inputs to my estimate, so I have summarized my estimate in the table below. I provide mine probabilistically with low-mid-high ranges.
* some of what BOEM calls “contingent resources” falls into this category
Below is a compilation of the 3 EUR estimates, including both shelf and deepwater.
I finish up with a projection of future GOM production using my EUR estimates ranging from 30-37-47 Bbo. Keep in mind that this includes both deepwater and shelf, but shelf production is starting around 200 kbopd or so in 2016 and declining in future years. I never show total production over 1.7 mmbopd, and show it going out to 2059 in the low case, to 2073 in the mid case, and to 2094 in the high case.
The downside case shows a peak in 2020, and then a gradual decline, dropping below 1 mmbopd in the late 2020s, and below 500 kbopd in the late 2030s. The midcase shows a peak of 1.6 mmbopd through the early 2020s, followed by a plateau of 1.55 mmbopd in the late 2020s, then declining below 1 mmbopd in the late 2030s. The high case predicts a peak through the 2020s of 1.65 mmbopd, followed by series of plateaus ranging from 1.6 mmbopd down to1.5 mmbopd through the mid-2030s, followed by a gradual decline to below 1 mmbopd in the mid-2050s.
Do I really think GOM oil production could continue to 2094, as shown in the upside projection? Remember, this is a Business As Usual projection, assuming fossil fuels will continue to be needed and be “affordable”.
If you assume that there is no way production could continue past 2060 – then the downside case still produces 30 Bbo, the midcase EUR is 37, and the upside case has already produced 42 Bbo of its ultimate EUR of 47 Bbo.
The following table shows how the different EUR projections break down by decade through 2090.
Note that I am still a working stiff, and will respond to comments as time allows.
Hi all,
If anyone has posts they would like to share, I can be reached at peakoilbarrel@gmail.com.
SouthLaGeo’s post is a fairly high bar in my opinion, if you are unsure, you can run a post idea by me before proceeding, a rough outline or even a few sentences (an introduction perhaps) would be enough.
Thank you SouthLaGeo, excellent work!
Hi Dennis,
I’ve been thinking about doing a post [stimulated by SouthLaGeo’s excellent piece] on seismic applied to oil/gas E&D if anyone is interested but not sure how to do this without resorting to (digressing into) some rather intimating math.
Meanwhile, demonstrating what’s possible nowadays: full-wavefield seismic inversion can be used to estimate subsurface elastic models by iteratively minimizing the difference between observed and simulated data − assuming you can live with the extreme computationally intensive cost: you actually need a super computer these days.
Anyone wishing for a taste how this state-of-the-art stuff works I recommend watching the excellent FULL WAVEFIELD INVERSION technology animation video produced by ExxonMobil. Cool stuff.
http://corporate.exxonmobil.com/en/energy/oil/technology/full-wavefield-inversion-technology-animation-video
“intimating” math?
I might be “intimidated.” So, I think that I would prefer intimate math.
PS: That video is cool!
“intimate” then, perhaps even cushy-cozy, at least undemanding. Then again, perhaps I’d best just find a rock to hide under. 🙂
cushy-cozy, at least undemanding
Next thing you know you will be talking about friendly numbers…
https://xkcd.com/410/
I’d best just find a rock to hide under.
That might be Gneiss!
We forgive you for your faults! 🙂
Well Fred, you have a choice: irrational, imaginary, friendly or intimate. Friendly numbers are the easiest to deal with. BTW Gneiss is nicer than Schist, especially deep Schist.
Hi Doug,
I would welcome a post, whether the maths are intimate or intimidating 🙂
Doug,
I second Dennis’ welcome. Show us the math, then tell us what it means and the significance and we’ll grasp what we can. I doubt we’ll call it Schist.
Jim
Thanks,
Next trip to Norway I’ll scarf some applicable data and visuals from Statoil. Cool graphics will probably do far more toward explaining advances in seismic science than anything: if my old computer is up to the task. In fact, advances in tomography applications have been of key importance in the North Sea: probably everywhere. My niece (petroleum engineer) showed me some amazing 3-D ray tracing techniques (tomographic inversions) at Christmas that I was clueless about until then.
If you need any help with your graphics I might be able to help out, pro bono for a good cause. I can handle high scientific precision for seismic data analysis to full GIS mapping CGM*PIP and GeoTIFF files and of course data analysis, graphs, charts, high resolution graphics both vector and pixel based.
This is what I use:
http://www.canvasgfx.com/en/products/canvas-x-16/industries#energy
Hi Fred,
TKS Good chance I’ll take you up on that offer. Have a good friend in Florida who I visit from time-to-time so might even bang on your door. BTW, I have a gazillion copies of Mathematica and would happily give you one. The company keep sending complimentary copies addressed to (now in Valhalla) wife.
Hey, you can reach me at fred dot magyar @ g m a i l dot com should you want to send me some graphics.
SLG – great post, thanks. I can’t argue with any of it really (and a lot of the geology is over my head anyway) but would suggest a couple of alternative possibilities.
1) With Stones, Horn Mountain Julia ramping up this year, Thunder Horse expansion this year and next, three or four minor tie backs next year and then Big Foot and Stampede in 2018 I think 1.9 to 2.0 mmbpd could be reached as a daily peak – though not as an annual average, and the availability factor would depend on ramp up rates, hurricanes and any other installation issues. After that though there is only Appomatox through FID and due in 2020. So unless there is some sudden activity, and projects are fast tracked I can see a rapid decline (8% per year) from 2019 to 2021 (again depending on ramp up rates, hurricanes etc.). New projects could come on, such as Mad Dog and Vito, after that if they are approved in 2017/2018, but that will require higher, sustained oil prices for here on I think.
2) In order to get the medium to high EUR cases there needs to be exploration and good discoveries fairly soon. I get the impression that the majors don’t think there is that much out there. There have been some recent disappointments after supposedly good discoveries like North Hadrian, Coronado, Hopkins, and Cascade-Chinook (I think has turned out not so good even though it is operating). Marathon, ConocoPhilips, Freeport McMoran, and Noble all seem to be pulling back from exploration. Shell and BP have been selling assets. ExxonMobil you never know with, but they don’t seem very active. Lease sales have been disappointing from USA and Mexican sides (we’ll see what happens with the next Mexican round as well). To hold some kind of plateau or slow decline out to 2030 and 2040 for the higher cases the new fields have to be started to be found and projects approved 2019 to 2025, at the moment that seems unlikely to me.
George, appreciate your insights.
Regarding #1 – you may be right in that near term monthly production could exceed 1.8. Horn Mountain Deep was not on my radar. Another Freeport project I could add is Holstein deep. But, every month, when I plot actual GOM production vs. EIA projection, the actual number is always less.
Regarding #2 – I do believe that to get to the highside EUR, some impactful new play needs to be found. I’m giving industry til 2020 to do this. Low prices are certainly delaying this type of exploration at this time. I’m not sure an impactful new play has to be found to get to the mid-case EUR.
One thing I did not mention in the post was the potential EUR uplift industry could get if they are able to increase Wilcox recovery factors from the current view of 10-12% to 20-25%.
They could try gas injection at 12000 psi to increase oil recovery factor. That’s one hell of a compressor, but I got a funky idea to get around the issue.
SouthLaGeo,
Thanks for very interesting overview and analysis.
Just for information, below is a chart showing EIA’s projection for US Lower 48 Federal Offshore oil and condensate production
source: Annual Energy Outlook 2016
Alex, thanks for the chart.
This chart probably includes offshore California, offshore Alaska plus offshore GOM.
Over the last few years, offshore GOM has been over 95% of the total, and I would assume that to be the case going forward. Therefore this is basically a chart of their offshore GOM projection.
The EIA is more bullish in the near term than me – more in line with what George Kaplan was saying above, and they also maintain high levels longer than me.
My quick ballpark estimate from the graph shows about 15 Bbo being produced from 2016-2040, giving a GOM EUR at 2040 of about 35 Bbo, vrs. my estimates ranging from 29 to 34 Bbo.
Alex’s chart does not include offshore Alaska.
Just like it says “Lower 48”.
SLG,
Yes, implied cumulative production in 2016-2040 is 15.3 Bbo.
The EIA’s numbers in the chart exclude Alaska offshore, but apparently include Federal Offshore California (PADD 5).
The numbers also exclude state offshore in Lower 48
Thanks, SouthLaGeo!
SLG,
Very good work. It brought back a lot of memories. I worked the Central and Eastern GOM in the mid-80s when area wide leasing started. I always thought of the industry as pushing the edge of the technical envelope.
What do you think about offshore Cuba? Is there any chance that American companies will venture that far south now that we have reopened relalions with Cuba?
Maybe Mexico more than Cuba,
OIL MAJORS ARE EYEING UP MEXICO’S NEXT OIL AUCTION
“The prospects for the new auction boosting output are good, as the new blocks are primarily deepwater non-conventional reserves, which account for 76 percent of Mexico’s prospective resources. The next auction includes 10 deepwater exploration and production blocks located in the Gulf of Mexico. These contracts will be awarded in December and have a lifetime of up to 50 years. According to press reports, oil majors such as Shell, Chevron, ExxonMobil, BP, Total, Repsol and Statoil are among the 21 companies registered to bid for the blocks.”
Meanwhile,
“Pemex’s exploration rig count fell from 163 in October 2009 to 14 as of May, a nearly 91.5 percent drop compared to a 78 percent decline in the U.S. over the same period, according to data from Baker Hughes.”
http://oilprice.com/Energy/Crude-Oil/Oil-Majors-Are-Eyeing-Up-Mexicos-Next-Oil-Auction.html
European multinationals have been drilling offshore Cuba for many years. The deep water play has very thin sands with a little bit of oil.
Don’t forget that Cuba has had relations with all sort of countries and they have invested in joint ventures with the Castro family dictatorship (the largest oil industry investor was a Canadian outfit).
Cuba’s lousy economy and high poverty are the result of the dictatorship’s rather quaint Marxist ideas, which they soften a little bit to make deals with multinationals. However, their terms can be lousy. For example they serve as the sole employer for all Cubans, and sell their labor to the joint venture at a pretty high price. The worker sees about $30 a month, so the government in a sense is selling slave labor. Workers in these joint ventures can’t live off those salaries, so they need “tips”, or get overseas travel perks, or they steal from the joint venture.
I had an aunt working in one of those for years. The job was pretty useful, it helped her arrange the escape of her 19 year old daughter. So, in conclusion, I don’t think the Castro family dictatorship will be getting much more business. Once it has been destroyed, all the communist leadership is in jail or reeducation camps, and the country can return a bit towards civilization it will probably be a much better investment target. But I’m afraid it won’t be doing much in deep water. The big business line will be importing natural gas from the USA to generate electricity, refurbishing the Cienfuegos refinery, and eventually building nuclear power plants to export electricity to the USA.
Thanks Fernando.
I take it then that Cuba will not produce much oil and gas in the future. W/o Venezuela,
What are their options for energy w/o cold hard cash to buy on the open market. Russia?
John, Cuba does produce oil. But it’s declining very fast. Most of it is in carbonates right on or slightly off the northern coast. There’s also a bit of production from old fractured rocks.
Now that Venezuela is tanking they requested oil deliveries from the Russians. The country seems to be having hard times now that all that cash they stole from Venezuela is drying up. Obama is working hard to keep the Castro dictatorship in power, but I really don’t know what’s going to happen.
I do know they are much more repressive, and their fear is reflected in their Venezuelan puppets. Maduro travels to Cuba for short trips and whenever he comes back he’s more irrational and orders more arrests and torture of prisoners.
John,
I don’t know that part of the Gulf too well. I do remember the recent big hub-bub about an exploration well being drilled offshore Cuba. It was a year or two after Macondo, and everyone thought there was going to be another big incident. No U.S.-based oil companies could be involved in the well. The well was a dry hole, and, as far as I know, everything went off incident free. There may have been 1 or 2 additional exploration wells drilled since then (though it may be the wells were just being considered, but were never drilled).
Of course the big interest now is in offshore Mexico. One of the more prospective areas there appears to be the southern extension of the Perdido Fold Belt into Mexico waters.
SLG
Ok, thanks again. Could you possibly post a trend map of the Mexican GOM trending into the US Western GOM. That would be cool to see.
Unfortunately, anything I have seen showing prospective trends offshore Mexico would be proprietary and I can’t show.
Thanks SLG, I understand completely. I just found this link about the Perdido Fold a Belt. I just kinda of wanted to know about where it is located.
http://www.searchanddiscovery.com/documents/2014/30331colmenares/ndx_colmenares.pdf
John,
Thanks for the link. Great overview of PFB.
Thanks for this post SouthLaGeo,
I learned a lot!
Thanks for your detailed analysis. However:
Offshore greenfield project commitments are down
“Rystad Energy’s latest market analysis shows that E&P companies have been hesitating to engage in greenfield projects amid the current market downturn, resulting in the lowest offshore project commitment since 1998.
Only 43 billion USD are estimated to be committed this year, which is over 75% less than the average volumes sanctioned from 2011 to 2014. In terms of the number of projects, only around 50 projects are expected to proceed, a number that historically has been threefold.”
http://www.rystadenergy.com/NewsEvents/PressReleases/offshore-project-commitment
Matt,
Thanks for the links.
As far as I know, the only deepwater Gulf of Mexico projects that are not going forward are Moccasin and Hopkins, both Wilcox discoveries that were, as far as I can tell, “condemned” because of poor appraisal results. I do concede that some projects may be delayed, but, as far as I know, none of the projects I have listed have actually been cancelled.
With the big boost in offshore development spending 2011 to 2014, coupled with a dramatic fall off in discoveries 2011 till now, I’m going to guess and say there may only be around 120 offshore prospects (oil and gas) now available for consideration for future developments (i.e not currently through FID). About 40 t0 50 will be smaller tie backs. The number is probably shrinking even at current low development rates as the discovery numbers are even smaller. All the pre 2010 discoveries are projects that didn’t make the cut for development when oil was above $100 per barrel. Sudden higher prices aren’t going to turn that around quickly, even with the much advertised ‘efficiency gains’ we see. There may be other stranded gas areas that don’t get advertised much as well though, so FLNG might be a future growth area after the current glut subsides.
Hopkins rumored to be Miocene, not Wx
Another harbinger for peak oil
South Korea’s Hanjin Shipping Files for U.S. Bankruptcy Protection
http://www.wsj.com/articles/south-koreas-hanjin-shipping-files-for-u-s-bankruptcy-protection-1473002745
The collapse of the firm is just the latest evidence of an unfolding implosion of the South Korean shipping and shipbuilding sectors.
http://www.wsj.com/articles/the-global-forces-behind-koreas-shipping-collapse-1472632705
Can someone check to which extent the down-turn in the oil-industry has contributed to lower orders for platforms and FPSOs in Korea?
I think such events are going to become more common and are the first canaries in the coal mine to die. This kind of thing will have major implications on SouthLaGeo’s primary asssumption, i.e.:
And, I will be assuming a Business As Usual future – by that I mean that fossil fuels will continue to be an important an energy source, and the world will continue to be able to afford them.
I just don’t see a BAU future being in the cards long term. First there is a growing understanding and consensus that we simply cannot continue to burn fossil fuels indiscriminately as we have up till now.
Then there are all the disruptive technologies in the pipeline (no pun intended) that are impacting manufacturing and thus future trade. I see a new world order unfolding as things like 3D printing make manufacturing of goods local and cheap. There will be less need for transporting the quantity of goods that make a company like Hanjin viable.
Add to that things like disruptions in personal transportation such as self driving EVs that are not privately owned and energy generation by solar and wind and I think sooner rather than later the big oil companies will be forced to contract even more and will be forced to change their business models or go out of business entirely.
I think change and disruption to the old BAU model will start to accelerate exponentially from here on out!
Well Fred, you’re no fun!
And you did have to highlight the only section with a typo!
All kidding aside – thanks for the comment.
If it is not BAU, as I assume, then you’re right – none of my projections mean anything and we have more serious problems ahead of us.
On the two legs of your main assumption, it might not be easy to determine how important oil will be in the future, but we might get an idea of how affordable it will be by knowing how expensive it has become to develop and produce with time and trend from shelf to deepwater.
All assumptions aside, I still greatly appreciated your post from a technical and scientific perspective. Brought back some memories of the days when I worked for a software company that sold seismic analysis tools to the oil majors and I had to troubleshoot their files. Though more often than not I probably spent more time dealing with the bureaucracy of the non disclosure agreements from their legal departments than working with the fun stuff and their geologists 🙂
Again thanks for a great post!
I mean other disruptions. The oil supply system is out of whack since 2005.
Selective snippets:
“The three South Korean shipbuilders recorded combined net losses of $4.9bn last year, up from $2.5bn in 2014, as demand for another main part of their product portfolio — oil rigs, drilling ships and floating production and storage vessels — was crushed by the slump in crude prices.
Key customers, such as Maersk Line, the world’s largest container shipping line, are hurting because of the sluggish state of global trade, and the protracted downturn in commodity prices, led by oil. Maersk’s parent company warned in February that freight rates were lower than during the financial crisis.
The Board of Audit and Inspection, a state agency, said this month that Daewoo Shipbuilding had overstated its operating profit in 2013 and 2014 by $385m and $959m respectively, by allegedly underestimating the production costs of oil rigs and floating production and storage vessels.”
https://www.ft.com/content/d74127ac-3140-11e6-8825-ef265530038e
Since late 2013, there has been an overall decrease in the number of sanctioned projects, according to Wood Mackenzie. In the past year, 46 conventional projects have been deferred, with the biggest decline hitting deepwater.
http://www.drillingcontractor.org/wp-content/uploads/2015/10/Wood-Mackenzie-Costs-01.png
Article here:
http://www.drillingcontractor.org/pressures-mount-as-industry-goes-deep-into-survival-mode-37357
SouthLaGeo
Based upon the Macondo blowout spill volumes, was that the most productive well ever drilled in the Gulf of Mexico? Just your opinion.
clueless,
Far from it. Spill volumes from Macondo were about 5 mmbo, and that number is on the high end of the estimated range. In fact, that well opened up a trend that is being produced by other wells as we speak. (The Macondo well did produce at unprecedented rates – calculated by some to be over 60 kbopd. “Good” deepwater wells produce at maybe 20-25, maybe up to 30 kbopd.)
I am aware of deepwater wells that have produced over 60 mmbo, and are still producing. In the sweet spots I mentioned, the Mars Basin and Southeast Green Canyon, per well recoveries routinely average over 20 mmbo. In other areas, 5-15 mmbo cumulative production wells are not uncommon at all. In fact, they need to average about that much to make then economic.
When it comes to oil rate, one has to remember that’s a design objetive. I have never seen anybody justify properly a design rate higher than 40 thousand BOPD (it’s either too dangerous or doesn’t make economic sense). Don’t forget those high rate wells produce from very deep hot reservoirs, this creates a heat problem at the wellhead which has to be accounted for. The high temperature expands everything, it can make a mess, cause seal failures, jerks annulus pressure all over…
SouthLaGeo. Thanks for a very interesting bit of work. (A Lot of Work, actually!!)
You had to use some constraints to limit the scope of your project, and BAU is probably the only solid ground you had to stand on.
But I guess your last word in you post above is the elephant in your (and all Oil’s) room isn’t it? ‘…economic.’
Much of the decision-making regarding development of these new discoveries will have been made when oil prices were a lot higher than they are today, or are ever likely to get.
You point out that
‘…In other areas, 5-15 mmbo cumulative production wells are not uncommon at all.’ This would suggest that while there are some wells that produce at those rates, the average is way below that.
Then you note ‘ In fact, they need to average about that much to make then economic.’
So, at below $50 down to $40, $30… what proportion of GOM’s wells (importantly what proportion of new production which could come on line) do you think will be ‘economic’?
Until 2009 EIA tracked well production in the USA (budgets were cut then, but they also might have thought the number of unconventional wells made the numbers a bit worthless). As below there were very few wells above 12800 bpd, but they produced 10% of the total. All those wells were offshore – at that time I think probably a good number on Thunderhorse. There may have been more and larger ones since as there have been more deep water developments. Note for deep water these wells can fall off quickly, as soon as they cut water they go down like a sack of potatoes. The largest offshore well I’ve known achieved 65,000 bpd for a short time. One problem with the big wells is you need to have an equally good injection well and/or really big pumps (actually a bigger equivalent volume well because of oil shrinkage) for pressure maintenance. The biggest well ever I think was an on shore blow out in Texas early on in the industry which they reckoned got over 200,000 bpd.
I wish EIA still tracked this.
Thinking about it the water injection comment might not apply much to deep wells in the GoM, I’m not that familiar with the area in general (just a couple of quite specialised projects) but I think a lot of the fields rely on aquifer support and rock compaction rather than external water or gas injection.
There are a fair number of water flood projects in the deepwater GOM (maybe 20-40) – both more mature waterfloods in the older basin play fields, and more recent waterfloods in the subsalt Miocene. The most successful projects have achieved up to 50% total recovery efficiency (total recovery = 50% of the total original oil in place). And I’m familiar with at least 3 future projects that are planning water flood from day 1, or soon after first oil.
Don’t know of any gas injection projects.
Water injection makes a lot of sense for plumbed reservoirs where the sands are fairly homogeneous. I have seen water injection work ok in very deep Cretaceous and Eocene reservoirs in Venezuela (it’s amazing to see how many nice fat sands were deposited in the Eocene in northern South America and southern USA).
I supervised a team running reservoir models for that hot very high pressure environment, and we saw a very nice return from gas and water injection. But this type of project has to be tricked to get the gas in.
Exactly, one of the biggest subsurface reasons water flood projects aren’t successful is because the injectors aren’t connected to the producers.
SLG,
Can you please explain what you mean by “connected’?
Thanks!
Jim
It means the water injection and oil production are in the same zone – typically separated by faults – so that the water injection maintains the pressure as the oil is withdrawn. However sometimes connected is used in a bad way in that the water injector and oil producer are directly connected by a fault line and the water ends up flowing directly from one to the other and bypasses all the oil – thats game over and a new injector has to be drilled. What is wanted ideally is the water injected spreads out evenly and moves up through the formation displacing as much oil as possible from the rock pores as it goes – this is a lot easier in light oil with sandstone reservoirs in nice even layers with high porosity and permeabilty (and lower salinity water is also good). Less easy with heavy oil, carbonate rocks, stacked reservoirs etc. understanding this sort of behaviour is really the unique skill owned by oil companies and no others which makes them the money.
George, thanks!
Jim
Adam,
Thanks for the comments.
Your last question is a toughy. Operators will say they are doing there best to try and make their deepwater projects viable in a low price environment, even if they were sanctioned, or at least discovered, during high prices. One thing operators hate to do is to cancel projects because then they can’t book the reserves associated with the project – and booking reserves is the life blood of oil companies. I’ve seen press releases regarding Appomattox and Mad Dog 2 where the operators claim they have made large enough cuts in projects costs to at least make the projects more viable.
Some deepwater GOM projects were so close to coming on line when low oil prices hit that the operators thought it best to just bring the project on line and “hope for the best”. (Jack/St.Malo, Lucius, Heidelberg, Stones) Most of these projects are, I suspect, at least profitable on a “go-forward” basis, but, it is unlikely they will pay-off the significant sunk cost.
I do believe individual well investments can be profitable in a $40 oil environment, especially if infrastructure is already in place.
Hi Adam
When oil supply runs short in 2019 oil prices may rise to previous levels.
Has not the world’s economy already signaled that it cannot afford oil at ‘previous levels’? Isn’t that the problem? If we could afford it, would not the price be back there already?? I mean, that was tried with $120 oil, and it broke the economy’s back, and it all fell over.
Hi Adam,
Prices were high from 2011 to 2014, the World economy did just fine.
The reason for the drop in prices is fairly straightforward imo, oversupply of oil.
When supply balances with demand (projected for 3Q2017 by the IEA), oil prices will rise, by 3Q2018 the oil price is likely to be higher than $85/b (in 2016 US$). By 2020, the oil price may be over $100/b.
Rystad Energy -The lowest offshore project commitment since 1998. – July 29, 2016 (Worldwide – not just the GoM)
http://www.rystadenergy.com/NewsEvents/PressReleases/offshore-project-commitment
I guess that most people have seen this chart already. But for anyone who missed it…
http://www.eia.gov/todayinenergy/detail.cfm?id=25012
Low oil prices => projects postponed => less supply by the end of this decade – early 2020s = > higher prices => projects reactivated.
Only a few, if any, higher-cost projects will be canceled forever.
Hi AlexS,
Very concise, thanks.
And correct imo.
I have a new update on shale oil & gas production in the US, here.
Enno
Have you gotten any inquiries from media, analysts or big funds to discuss your site and all the data you have compiled? Great work you are doing.
Reno,
Thanks!
And yes, so far I’ve gotten requests for the data, which is why I’ve now decided to offer it.
Thank you. Completions, a bounce from -77%
Thanks Chart Monkey,
For this overview, and the others, I recommend using the filters to either look at gas-focused basins (Marcellus, and any “Other” basins), or oil-focused basins (the rest). Combining the two may say something very generally about shale activities, but is probably in most cases not intended.
Thanks. It’s very helpful to look at oil and gas separately. (Most people mix them up which gives GIGO conclusions.)
Shale *oil* has been the profitable side of the business, so the constant reduction in well quality and the fact that it’s peaked is very significant.
Shale *gas* has always been a nearly-unprofitable business without the oil. I was going to say that they seem to be getting better at getting gas out, but it turns out that’s only in the oil-focused basins… in the gas-focused basins, the decline rates on gas wells are actually getting worse. This doesn’t look financially viable.
speaking of financially viable.
http://oilprice.com/Energy/Energy-General/How-Intermittent-Renewables-Are-Harming-The-Electricity-Grid.html
Demand for oil and nat gas, worldwide are at record levels and are increasing each and every year. It is business as usual. Countries worldwide continue to prospect for, preserve and secure reliable new supplies of both oil and gas. What ever the reason for the saudi decision in Nov 2014 they have every reason to revisit it again. As SS has pointed out before, a “stated” OPEC cut in production is what changes the mindset of traders, do not be surprised to see that sometime this year. Based on this article over at Rystad break-even cost are dropping across all plays and there is no reason to believe further cost reduction can not be found as the industry is very good at this, how much further can be debated.
http://www.rystadenergy.com/NewsEvents/PressReleases/shale-well-breakeven
I won’t take the time to address a number of other misconceptions you are plagued with including but not limited to these nonsensical gems:
“I was going to say that they seem to be getting better at getting gas out, but it turns out that’s only in the oil-focused basins… in the gas-focused basins, the decline rates on gas wells are actually getting worse” complete horse shit!
“Petroleum at current prices is too cheap to justify extensive exploration, and simultaneously is more expensive than superior alternatives. Petroleum has already priced itself out of nearly all markets, with transportation being the last significant holdout.” beyond naive, factually wrong, there are ZERO, let me repeat that there are ZERO “superior” alternative to oil and nat gas currently available or can be made available to any significant degree within the next 2 decades.
Do us all a favor and put down the crack pipe long enough to highlight exactly which markets of the “nearly all” petroleum has priced itself out of. Furthermore when you are done making that list, please explain why demand of oil has never been higher while at the same time, oil according to you, has lost market share to these nonexistent superior alternatives. You truly have so little understanding of how the world really works and your understanding of the oil and gas industry can be compared to that of a goldfish.??
Texas Tea, do you really expect us to accept an article on ‘OilPrice.com’ written by Gail Tverberg that claims ‘Intermittent Renewables Are Harming The Electricity Grid’ as an unbiased objective analysis of what is actually happening and what the potential of renewables are?
That article is so full of busted myths it would be difficult to know where to begin to address all the fallacies contained therein! I could provide hundreds of links supporting my point but I strongly suspect that you would not accept any of them because they would go against your deeply held views to the contrary regardless of actual facts.
Here’s but one:
http://www.energypost.eu/stanford-world-can-go-100-wind-water-sun-2050-save-money/
Whether you like it or not your claims do not hold water, or should I say oil…
At an absolute minimum you are either in deep denial of reality or truly do not understand how disruption occurs. And massive disruption is occurring simultaneously on multiple fronts. I won’t even mention climate change and the main raison d’être of this very site, or do you not believe ‘Peak Oil’ is real and has consequences that are rippling throughout our global industrialized civilization at this very moment.
Here’s a direct link to the actual study with all the data:
http://web.stanford.edu/group/efmh/jacobson/Articles/I/CountriesWWS.pdf
It kinda makes me wonder why we bothered with fossil fuel at all and didn’t just go straight to ‘renewable’ wind and solar from the get-go back in 1750.
An indirect answer: why didn’t the 5th century BC Greeks forget about wood, and go straight to coal?
The direct answer: It took longer to make wind and solar cheap.
Texas Tea
As a steadfast shale supporter do you have any view on the new shale play on the north slope Alaska. There is a small Australian company that have drilled and cored the HRZ. They are making some very big claims about potential flow rates as they state the oil is in the vapour phase. Normally I would take little notice but Paul Basinski is behind the prospecting. They plan a second well in Q1 2017.
http://88energy.com/
The Well Quality tab: interesting! In the end they will suck a well dry completely in the first day after completing it! 🙂
Enno,
Thanks for a new great update!
Back to the discussion on the Permian LTO production volumes in previous thread.
In the table below, I have compared your numbers for the Permian by key formations with similar numbers from the EIA/DrillingInfo report and the number for total Permian basin production (LTO+conventional) from the EIA Drilling Productivity Report. All numbers are for May, like in your report.
Your chart includes more formations than the EIA-DI report, but I think the EIA includes the volumes from some smaller formations in totals for the big ones. (Thus, Wolfbone is a combination of Wolfcamp and Bonespring).
The discrepancy between yours and the EIA-DI’s numbers is huge: 475 kb/d.
Furthermore, your numbers imply that more than half of Permian production is still coming from conventional reservoirs.
As you say, you are using statistics from TRRC (for Texas part of the Permian). Hence, part of that discrepancy can be explained by under-reporting by TRRC for the recent months. Thus, TRRC number for total Texas production in May from its last report (August 2016) is 281 kb/d less than the EIA’s latest estimate for Texas C+C (2911 and 3192 kb/d, respectively). Permian LTO may account for about half of that discrepancy
But the key explanation that you gave in the previous thread is that you include only production from horizontal wells, while the EIA-DI report likely includes some output from vertical wells. The biggest difference (almost 400 kb/d) is for the Spraberry formation, where a lot of oil is produced from vertical wells.
In my view however, in this particular case, the criteria of horizontal drilling is not correct.
Straberry has all characteristics of an unconventional play, so the EIA, DrillingInfo and others have reasons to classify oil produced there as LTO.
From a paper published in 1953:
“…the Spraberry has presented many problems in well completion and operation and has demonstrated unique reservoir performance characteristics.
The pay section consists primarily of a few fine grained sandstone or siltstone members in a thousand-ft thick section of shale, limestone, and siltstone. Since porosity averages only 10 per cent and nearly all permeabilities are less than 1 md, conventional core analysis does not delineate the “pay” section.
“An interconnected system of vertical fractures, observed in cores, provides the flow channels for oil to drain into the wells but most of the oil is stored in the matrix since the void volume of fractures is estimated to be less than 1per cent of that in the sand.”
https://www.onepetro.org/journal-paper/SPE-953177-G
There were some sweet spots (naturally fractured zones) in Spraberry where oil could be produced economically with ordinary un-fracked vertical wells, but most of oil could not be extracted with conventional techniques. Therefore, the formation was once called “the world’s largest unrecoverable oil reserve”.
http://dailyresourcehunter.com/the-spraberry-formation-cash-in-from-this-1951-time-magazine-article/
That has changed in the second half of the 2000s, when producers started to employ modern fracture stimulation techniques, like hydraulic fracturing, which led to a sharp growth in production.
Spraberry formation oil production (kb/d)
Until 2012, Spraberry was developed with fracked vertical wells, unlike the underlying Wolfcamp formation and other U.S. tight oil plays. This is the explanation from an article published in 2013:
“In fact, it’s important to note that the Spraberry … is different than other U.S. shale plays. As noted the shale is relatively thick, in some cases 1,500 feet. With that type of pay-zone drillers can cut costs by planning vertical wells, instead of more expensive horizontal wells.
It’s all about economics — and so far the vertical Spraberry wells are paying off the best.”
http://dailyresourcehunter.com/the-spraberry-formation-cash-in-from-this-1951-time-magazine-article/
“… there’s different characteristics between the Spraberry and the Wolfcamp.
The most important thing that you and I need to know is that the Wolfcamp is proving to be much more economic with horizontal wells. So instead of the Spraberry wells that are predominantly vertical, the Wolfcamp wells are utilizing horizontal laterals
http://dailyreckoning.com/u-s-oil-boom-bonanza-pioneer-hits-pay-dirt-in-the-spraberry/
However as drilling and completion techniques evolved, producers found more economic to uze horizontal wells.
As a result, from 2012, the share of horizontal drilling in Spraberry has been increasing.
The chart below is from a recent presentation by Pioneer:
Is this a peak I can see here?
Also, is this formation solely responsible for the lower than anticipated decline in the area?
The decline in the Permian was relatively insignificant (-2% in July vs. March) and was the result of reduced drillling due to low oil prices.
According to the EIA/DrillingInfo data, the decline was similar in 3 key Permian formations: Wolfcamp, Bonespring, and Spraberry
As oil prices rebounded from 1Q16 lows, oil rig count in the Permian has already increased by 70 units (+53%) and the basin is expected to lead the recovery in U.S. oil production.
Maybe I am a bit slow here, but Permian has increased from 0,8mmpd to 2 mmbpd from 2008 til 2016. In the same time spraberry/wolfcamp has increased from 0,2mmbpd to 1,1mmbpd -> 75% of the baken increase comes from this?
How big is the area, how saturated is it? i.e how much more can you really squeeze out of it?
Daniel,
Geographically speaking, the area is huge. It includes SE New Mexico, most of West Texas and the Southern Texas Panhandle.
The West boundary is about Carlsbad, NM,
Midland, Texas is roughly the center.
The North limit is about Lubbock, Texas
Terrell and ValVerde Counties, Texas are about the Southern boundary.
The East boundary is about Abilene, Texas.
Immigrants are discouraged; Although visitors are allowed if they have money and promise not to stay.
The natives aren’t that hostile. I never had one refuse to put regular milk in my coffee.
Alex,
Thanks for all the info and feedback!
Because of this discussion, started in the previous post, I decided to investigate this issue further with the great support of Mike Shellman, who has experience in the Permian himself, and also contacted a few buddies who are even more familiar with the area.
I think the main conclusions from this feedback are:
– Indeed quite many vertical wells were/(are) drilled in LTO formations like the Spraberry, and all of these wells are also frac’ed, although maybe not with the same force as is applied to horizontal wells.
– There are a few non-LTO formations, like the San Andres, where at least some of the horizontal wells are not frac’ed.
– Still the impression is that by far most of the horizontal wells (>90%) in the Permian, since 2009, are in LTO formations, which require frac’ing.
This of course complicates the analysis, but also in the other basins, due to different formations, lateral lengths, and frac sizes, it’s never completely an apples vs apples comparison.
I consider the differences in well production profiles, and well costs, between vertical & horizontal wells in LTO formations as too large. Therefore, I will at least for now stick with my focus on horizontal wells, which may leave out a significant part of LTO production in the Permian (and also may include some conventional horizontal wells, although these could be filtered out using the formation filter).
Still, a very useful lesson.
Enno,
Yes, tight oil formations are not uniform, and there are big differencies in geology even within the same formation. Besides, various drilling and completion technologies are used to extract hydrocarbons, and it is difficult to find a single criteria to classify produced oil as LTO or conventional.
In my view, a very important part of your work is to compare historical changes in well performance in various LTO plays and subplays. In that sense you are right that you will continue to focus only on horizontal wells.
But I think it will be useful for the readers of your blog if you clarify that total production numbers for certain basins, particularly Permian, exclude LTO produced with vertical wells.
Thanks again for all the work you are doing!
Thanks, Enno:
Newark Field (Barnett Shale) was discovered in the early 1980’s and produced gas from vertical wells for many years; there have been vertical Bakken wells that produced commercial quantities of oil in North Dakota since 1951. Until the term “unconventional,” was coined in 2001, oil explorationists did not know, nor care what defined conventional or unconventional resources. Whatever we drilled for, or thru, was either easy to produce, hard to produce, or would not produce at all. I perforated, acidized, frac’ed and cursed at the Eagle Ford shale in the early 1980’s and could not make it work. We did not think of it then as unconventional; it was just shale, that had oil in it, but would not produce. Same as the Wolfcamp in the Midland Basin where many people looked for porosity and permeability anomalies for decades in hope that, otherwise dense shale, would produce. Some of the best production I ever participated in was associated with a buried reef in the Wolfcamp to Dean Formation transition; we drilled those wells vertically, put a little acid on it, and here she came. Half of the Eaglebine shale play in the East Texas basin consists of the Woodbine and you won’t find anything more conventional than the Woodbine. It’s made nearly 5.5 GBO from East Texas Field alone.
I don’t think you would find many West Texas oil men refer to the Sprayberry as “unconventional” either. It was just crummy rock that was hard to produce. But produce it they did, nearly 1 GBO of oil from some 8000 plus wells drilled and completed before 2007-2008, all vertically drilled and all frac’ed. I baked a dozen myself in the early 1980s with stage frac’ing techniques developed in N. Louisiana (Pine Island) 40 years prior. Lots of reservoirs throughout the world are “tight” and produce light oil; that does not make them unconventional. I think the definition of unconventional is HOW the resource is produced. A combination of very old technologies, horizontal drilling and stage frac’ing were combined in the prefect recipe in 1996-1998 in the Barnett play and the term “unconventional shale plays” was born and now live in infamy.
So regardless of what the EIA says (which we tend to ignore quite often in the oilfield anyway) I believe Enno’s definitions of “unconventional” are essentially correct and the manner in which he segregates production data is absolutely correct. Shale + horizontal laterals + stage frac’ing = unconventional. When I look at his data in the Permian I am not in the least bit interested in vertical Sprayberry production prior to 2007- 2008. I want to know what has occurred since then. I mean, one can drive one’s self batty trying to define what is a resource bed, what’s conventional, what’s not, what’s old, what’s new (there in nothing “new” in the Permian Basin, by the way); you have to draw the line somewhere. I think Enno’s data is great and I use it all the time to argue how horribly unprofitable the shale oil biz actually is ;).
Mike Shellman
Mike says: “Until the term “unconventional,” was coined in 2001, oil explorationists did not know, nor care what defined conventional or unconventional resources. ”
But, see below where I just copied a portion of an article. Not a “dimes worth of difference” between “non-conventional” and “unconventional,” in my opinion. Further, in the 1980’s when we were receiving $.75 of credit per mcf of coal seam gas, I can assure you that oil and gas explorationists did know and care what qualified for the credit.
Non-Conventional Fuel Tax Credit
Peet M. Soot, Ph.D., P.E.1
ABSTRACT
Coal-seam methane, along with certain other non-conventional fuels, is eligible for a tax credit.
This production tax credit allowed coal-seam methane producers to receive $0.7526 per million
Btu of gas sold during 1986. In 1987, this credit rose to $0.78 per million Btu. The tax credit
is a very significant element of the economic analysis of current coal-seam methane projects.
In today’s spot market, gas prices are around $1.50 per million Btu. Allowing for costs of production,
the gas producer will net more income from the tax credit than from the sale of the gas.
The Crude Oil Windfall Profit Tax Act of 1980 is the source of this tax credit. There were
some minor changes made by subsequent legislation, but most of the tax credit has remained
intact. Wells must be drilled by 1990 to qualify for the tax credit but the production from such
wells is eligible for the tax credit until 2001. Projections have been made, showing that the tax
credit should increase to $0.91 per million Btu for production in 1990 and $1.34 per million
Btu in 2000. Variables which may decrease the tax credit from these projections are dramatical
But those Pine Island wells were pretty skinny. I remember we drilled the well with casing to save money. Everything was itty bitty, even had those bonsai pumping units.
Alex, Mike,
Thanks for all the very useful info.
“But I think it will be useful for the readers of your blog if you clarify that total production numbers for certain basins, particularly Permian, exclude LTO produced with vertical wells.”
Alex, good point & I completely agree. With the next Permian update, I will mention this.
Thanks! Suggestions for improvement: the graph should include as a title the setting under “where?” so that it is clear to which area the data relate to, e.g. Bakken Eagle Ford, North Dakota, Texas etc
The stated assumptions at the beginning caused me to stop reading.
The future for natgas is very unclear and it would be worth having some analysis of it, but that is explicitly omitted.
However, the future for oil is crystal clear. We know that Business As Usual for oil is *not* happening. Petroleum at current prices is too cheap to justify extensive exploration, and simultaneously is more expensive than superior alternatives. Petroleum has already priced itself out of nearly all markets, with transportation being the last significant holdout. The roadmap for elmination of oil from land transportation is clear and the price barriers are being crossed as we speak.
Which makes the entire analysis an exercise in fantasy. Perhaps there is some purpose to these counterfactual speculations; perhaps they are useful as input to a more realistic scenario. But there is nothing indicating that they are. So: waste of time.
I agree with you. If BAU for oil is not happening, then, all of the projections are meaningless.
Not ‘meaningless’. Analysis like yours is very important to our understanding. As I said above, you have to pick BAU as the basis for your analysis, as outside that cosy envelope the number of unknowable variables makes meaningful prediction of the future a tad difficult. A lot of experts make a living out of guessing.
There is a hell of a lot going on in the global energy patch. For example as we attempt to create substitutes for oil we have to use oil to create those substitutes. Try building a wind farm or a solar array without oil.
So every effort at substitution actually increases fossil fuel use, while the contribution by the substitutes to date is a disturbingly small percentage of global energy needs.
The economics of the energy sources are changing – and the difficulty of identifying and removing hidden subsidies of various energy sources is huge. But in the short term the drive towards effective mass-scale substitution can only increase fossil fuel use and the overall cost of energy to the end user – the planet.
Its no great surprise to see global demand for fossil fuels at an all time high, because, in part, the global drive to create substitutes requires FF to build it. The results of wind and solar (the great E hopes) – tho impressive individually – show no sign of even meeting 10%-20% of global needs in any time that will be useful, while we have to sustain the BAU of the global economy at the same time using some energy source, which by default has to be FF.
“But in the short term the drive towards effective mass-scale substitution can only increase fossil fuel use and the overall cost of energy to the end user – the planet. ”
As has been stated here before, we will only need about 10 to 15 percent of the energy used now to run our transport system once it is converted to electricity and made more efficient. Most of the energy used now for transport is just wasted as non-useful heat. A large portion of energy is used to produce liquid transport fuels, so there are hidden energy losses.
A solar panel has about $50 worth of energy embedded and returns more than $1000 worth of energy.
The energy inputs from fossil fuel are quickly returned and as the roll-out continues less and less will be needed. There are large advantages economically and culturally to investing in a growing business rather than a descending one. Not to mention the reduced pollution savings.
Yes, but isn’t the problem (well, one of them) that the energy in the solar panel has to be put in up-front; now. So mostly fossil fueled energy is needed to create a non-fossil fueled future.
FF use has to increase to create this investment in medium-life non FF solutions (not infinite life) like PV and Wind, while at the same time we have to keep BAU going, and also get the replacement-at-end-of-life production systems underway to sustain current and future PV and Wind systems.
These newfangled things (including all the minute electronic systems they need to convert and control them) do wear out and need replacing at some not-too-distant time if their blessing is to be enjoyed in perpetuity.
Let me know when an outfit like Maxim Integrated and its supply chain is end-to-end Solar and Wind and I will start to be impressed.
I can see you are a person that arrives at his destination before he leaves his origination point. Nice trick.
Wind power returns the energy used to built it in about…
6 months.
Point of production, or point of installation?
Does that include cost of transporting materials (rare earth elements from the Congo, for example, extruding aluminum, concrete production, tons of fiberglass,etc?)
What are the guidelines?
Yes, any basic analysis of net energy will include the supplies and components, and the energy involved in producing and shipping them.
Even Charles Hall gives wind an EREOI of 18, and that’s based on 20 year old data with small, inefficient turbines.
I think that I am with Duncan.
Isn’t there a law of thermodynamics such that if you started an engine running, and you ran it for 20 years, using 1 gal of diesel per hour, that at the end of 20 years, there is the same amount of energy in the Universe as when you started??
Nick, with all due respect, I do not think that an EREOI computation takes into account, e.g., that you have to hire workers. So, they need to buy cars to get to work, so you have to consider the energy used to make a car. And they need housing near the job site, so you need to — well, I assume that you get what I am talking about. So just continue the chain to food supply for the workers, schools for the workers children, and on to infinity.
Even Einstein could not come up with a valid answer.
Prove it to yourself. Start with a caveman in the middle of Europe who completely invents on paper everything needed to produce a turbine powered windmill. How much energy would it take to start mass producing them and distributing them throughout the countryside? Notice that he needs transportation systems, highways, global sourcing of materials, trained workers, and on and on and on. Just because fossil fuels made everything needed possible, does not mean that you can “assume” that everything that is needed is in place so we do not have to count it.
Yes, the First Law, and I suppose you’re treating the universe as an isolated system (no interaction with other universes). 🙂
Hi Clueless,
The EROEI calculation is an approximation and the result depends on where the boundries are drawn.
It also depends what is counted as “energy”.
If we are only going to count “work” and ignore energy that is lost as heat (friction and other thermal losses that are not put to any use to heat water (that is used for washing or some other useful process) or buildings during cold weather, then the useful energy used by society is far lower than the energy supply.
As an example consider oil, most of which is used in internal combustion engines. The “work” done by this energy is mostly to turn the wheels on vehicles and the conversion rate on average is about 25%.
For simplicity let’s assume 100% of petroleum fuel is used for road transport (in reality it is probably 70%), of the 29 Gb of C+C produced each year only about 7.25 Gb is converted to useful work (in my simplified example).
As we gradually convert the vehicle fleet to EVs, less energy will be needed as there are fewer losses in the EV with energy conversion from plug to wheel at about 75%. There are losses producing electricity as well if it is done by burning fossil fuels, but for wind and solar, the thermal losses are low relative to combustion processes and for combined cycle natural gas thermal efficiency is 60% (35% for typical ICE).
Overall an eventual conversion to mostly EVs and wind and solar would cut energy need in half due to fewer thermal losses.
Obviously it won’t happen overnight, the process will be gradual over the next 40 to 50 years as fossil fuel use falls due to peak fossil fuels and the high fossil fuel prices that will drive demand for fossil fuels lower.
Clueless,
Humans, and their housing and most of their transportation, are ends in themselves. You can’t allocate their energy use to energy production. Again, they are ends in themselves. Humans don’t exist to produce energy, energy is used to sustain humans.
There might be an argument to include the energy of commuting, but probably not. Any corporate fleet manager will tell you that commuting costs are a normal part of living, and aren’t part of the corporations costs. In other words, people will be driving somewhere. If not this job, another, or the unemployment office.
FF use has to increase to create this investment in medium-life non FF solutions (not infinite life) like PV and Wind, while at the same time we have to keep BAU going, and also get the replacement-at-end-of-life production systems underway to sustain current and future PV and Wind systems.
Absolutely false! There is no fundamental law that says we can’t significantly reduce our consumption of fossil fuels by doing away with superfluous uses of fossil fuels while diverting our remaining supplies towards a massive build out of renewables. We do not need all of BAU to survive. Most of BAU deals with production of products that supply artificially created wants!
The problems of transition are not technical or scientific. They are mostly political and are made infinitely more difficult by special interest groups that will tend to lose their power and wealth if renewables, especially of the distributed locally owned kind, ever become ubiquitous!
We do not need all of BAU to survive.
Like single passenger SUVs.
The average light vehicle in the US has only 1.2 people in it. It only gets 22MPG.
Lots of room for re-allocation of low value current energy use.
Thanks everyone for the wonderful feedback! Clearly a few diverging lines of thought there!
I remember doing several shifts at the chip board plant shoveling chip onto the conveyor because a micro-controller had blown and the variable speed drive chewed thru all three spare belts in an hour and we had to feed the plant wood-chip by hand until another belt and controller came from the other side of the planet.
Much as I appreciate the nouvelle-riche of energy systems in the form of very clever wind and solar resources, their lack of simplicity makes them even less tenable as a long term solution than the drill-a-hole+get-oil +burn-it of the present primary energy supply. While I am writing this beside a light lit by my solar system, my home-made LEDs are a dismal failure, and so my domestic lighting system will last as long as the hobby-bag of miscellaneous distant factory-made LEDs will. Then I’m back to a guttering tallow dip.
I agree wholeheartedly that much could be done to improve the efficiency of energy use to mitigate the energy used in developing the new alternatives. Could be done. But I honestly doubt it will be done at any useful scale. I mean – why should anybody reduce FF consumption when the world is awash with the stuff! Pick up the phone and order a tanker full off the rank anchored outside any major refinery or tanker port.
As JH Kunstler recently observed ‘We’d rather crash and burn than change anything about our behavior, or even our perception. ‘
I do so hope for the best, but I admit to suspecting that my fears for the worst will win the day, if it could be called ‘winning’.
Keep up the great work! Thanks, AA
“Much as I appreciate the nouvelle-riche of energy systems in the form of very clever wind and solar resources, their lack of simplicity makes them even less tenable as a long term solution than the drill-a-hole+get-oil +burn-it of the present primary energy supply. ”
You need to expand your view of oil production, oil refining and distribution. The oil industry is hugely complex and wasteful by nature, renewables are so much simpler and direct. It too needs constant input from itself and other fossil fuels to run, and can never run on it’s own. So in reality it’s system spreads out even further and into more complexity.
Also, there is no end date for renewables, so they are well worth any investment needed to bring them on line.
Hard to find anything simpler than wind and solar.
PV is a rock that generates power. It doesn’t get much simpler.
Wind turbines are just big propellers. The Dutch and Spanish were using them hundreds of years ago.
EVs are far, far simpler than infernal combustion engine vehicles. Electric motors have one moving part!
Hi Adam,
Fossil fuels can be used more efficiently and only about 40% of the energy is converted to useful energy, most is wasted.
Hi Adam,
Also see
http://peakoilbarrel.com/the-energy-transition/
I modified the growth of non-fossil fuel energy in the scenario below to a maximum of 7% per year for 20 years, up to 63% of energy being provided by non-fossil fuels, then the growth rate slows.
In 1973 oil and natural gas provided 67% of World primary energy (BP data) and the rate of growth of oil and natural gas consumption was about 7.4% per year on average from 1954 to 1973.
Growth rates for scenario above in chart below.
Some will claim this is not realistic. World oil and natural gas consumption grew at an average annual rate of 6.56% from 1910 to 1973, the average annual rate of growth of non-fossil fuel energy is 4.87% from 2016 to 2075 for the scenario above.
It would be interesting to show the actual growth rates for the last 20 years.
Hi Nick,
For non-hydro renewable energy alone growth rates have been high, but the energy provided is quite small compared to the total (about 2.8%).
When we add nuclear and hydro to renewables (non-hydro), there is much more energy (14% of primary energy), but growth rates are not very high. From 1996 to 2015 the average annual rate of growth in non-fossil fuel energy consumption was 2.46% per year. From 2011 to 2015 the rate of growth increased to 3.65% per year.
If we only look at wind and solar for the past 20 years the annual growth rate has been 25% per year, but since 2010 the rate has slowed to 21% and I expect the rate of growth will continue to slow to 10% per year or less.
Well, thanks.
Ok, I think your guesses for likely overall growth rates are reasonable. But:
1st, for purposes of analysis, it’s not really helpful to focus on an overall, composite figure. Each energy source requires it’s own analysis if we want to understand it.
2nd, what we really care about are not the likely rates of growth, which are affected by many things, but the maximum growth rates based on fundamentals like resource scalability, cost, maximum market share, etc.
In this respect we could look at some proxies. A good one might be the rate of growth of nuclear power in France, perhaps (I’m guessing) from 1970 to 1985.
Hi Nick,
I was trying to simplify the analysis and in that way reduce the number of assumptions.
I think we have seen the maximum growth rates already for wind and solar, the question is how quickly it will slow down (not known), I also don’t think narrowing the focus to a single nation tells us very much.
You are welcome to present your own scenarios.
World nuclear power consumption grew by 12%/year from 1975-1989 and by 2.2%/year from 1990-2004. Hydro has grown pretty steadily from 1987 to 2015 at about 2.4%/year. Other renewables (does not include hydro) grew at 15%/year from 2004 to 2015. Solar grew by 40%/year from 2001 to 2010 and by 33%/year from 2011 to 2015, it is doubtful that these rates of growth can be maintained. Wind power consumption grew by 24%/year from 2001 to 2010 and by 16%/year from 2011 to 2015.
Trying to create a future scenario requires many assumptions when there are too many variables. I prefer to keep it simple.
We got lots of economic layouts of what it costs to drill in shale.
The Exxon vid above shows what looks like a non trivial amount of money being spent for analysis before drilling happens — or doesn’t happen.
Do we have anything for deepwater wells, and how are the analysis costs divided among the wells drilled, or not drilled?
Watcher,
That starts to get out of my area of expertise, but, given the $200-300MM costs to drill and complete a subsalt deepwater well with a total depth of say 26,000, a great dealing of planning and analysis goes into it. Up to half or more of the costs of many of the deepwater projects I mentioned are well related, so that could be $2-3 B for a $5 B project. These “project” wells have to not only pay their own way but they need to support their share of the remaining projects costs, such as the platform, subsea infrastructure, etc.
One of the ways the costs of some of these projects are being cut back is by trying to optimize well counts – can you recover all the reserves from 1 or 2 fewer wells, because 2 fewer wells can reduce total project costs by $.5B.
A good start.
I was groping for the cost of analysis. I have a vague recollection that university startups were formed for doing the computer work to image below salt, and they were billing it with huge numbers.
So . . . two parts. What is the cost of analysis and how would that be allocated among an unknown number of wells.
We also talk about a somewhat trivial Opex number for shale, just letting it fill a tank and send a truck out every couple of days to drain the tank(s) of water and oil. For deepwater, you have food transport and people transport on helicopters.
I can remember a problem mentioned for Brazil’s far offshore field. Only one or two helicopter types in the world had the range to reach the platform.
Watcher, Not sure I quite appreciate what “cost of analysis” is? Just googled it and saw some terms I am familiar with – cost-benefit analysis, for example.
Tons of that sort of thing are done in the course of a major deepwater project. Analysis is performed on virtually every decision-
Has enough appraisal drilling been done?
What is the best type of platform?
Platform nameplate capacity?
Subsea or dry trees?
Number of wells?
Water injection?
On and on.
This is cool: http://www.iongeo.com/content/documents/Resource%20Center/Technical%20Papers/TP_SEGGEO_Subsalt_Imaging_Exp_Pro_Dev_Leveille_1109.pdf
ION is Institute of Navigation, which used to be a self serving group generating proceedings in which they (academics) would have a place to publish and have a symposium funded by booth rental by companies at which their grad students presented papers. Mostly focused on GPS spacecraft design re Cesium clock accuracy and antenna gain blah blah.
Wonder if the company IONGEO was attached. (Nope, 1968, predates)
Not seeing much for dollar quotes for the new subsalt tech.
The Ion company referenced in the link above is not the ION you reference, but is ION Geophysical Company, which is a seismic service company to the oil industry. Their specialty, as far as I know, is not advancing subsalt imaging technology. ION Geophysical has their specialties, but industry generally goes to CGG and Western (a Schlumberger company) for the latest in subsalt imaging.
The company referenced in the link is Ion Geophysical, a seismic service provider to the oil industry.
The seismic service companies that I am familiar with that are leaders in subsalt imaging technology are CGG, Fairfield and Western (a Schlumberger company).
The quest for better subsalt imaging is a big deal. In a typical deepwater subsalt project, over the many years from leasing to discovery to appraisal to sanction to first oil and on, improving the seismic image is a continuous process – through both acquisition of new seismic, or reprocessing of existing seismic.
My rule of thumb is to spend a minimum of 10 % of the total cost in geoscience/engineering and environment/safety evaluations and planning. However, that can be less if the spread rate is very high and/or contractors are offloaded some of the engineering. I’m assuming the basic 3D is processed and we have sea floor soil data already.
I’m very uncomfortable having work done by outside outfits. I’m a consultant now, and obe of the biggest problems I see is consultants who like to please the client and get slack. This can be poisonous.
This link is all about the current potential for an oil production agreement, and goes into more depth than most.
http://www.barrons.com/articles/can-oil-rally-after-russia-saudi-pact-1473131167
Shell starts production at Stones in Gulf of Mexico. Output expected 50k boe/d when fully ramped up at end of 2017. Sept 6th 2016
Hi all,
Jean Laherrere sent me the following (showing full email):
Dennis
in the post SouthLaGeo shows one of my graph: GOM deepwater HL oil production trending towards 11 Gb
HL oil production is a poor way of estimating ultimate and the best way is the creaming curve using backdated 2P discoveries
BOEM has published the GOM estimated 2P oil & gas reserves at end 2014
The creaming curve with backdated 2P is the best way to estimate ultimates
The GOM deepwater cumulative 2P discoveries is modeled with 4 cycles towards 11 Gb when SouthLaGeo believes that it is the double
It is possible if new cycles (there are already 4 cycles), but there is no deepwater discovery since 2012
Where is the new cycle yet to find?
I would like more graphs from him displaying his estimate and saying where are the new cycles in the deep US GOM.
best regards
jean
Hi all,
Jean Laherrere also sent a couple of charts, one was already used in the post (GOM Deepwater HL), the others are below.
Second chart from Jean Laherrere
Dennis, thanks for the responses, and I really appreciate the forwarded comments from Jean Laherrere,
Jean, I don’t have any graphs.
There have been discoveries since 2012. Guadalupe, Anchor, Fort Sumter, Sicily, Tornado – to name a few. None of these have been included in BOEM’s reserves because none of these projects have been sanctioned.
One area we disagree in is production from undiscovered fields. I give a range to that number of 1 – 4 – 8 Bbo. You are just looking at existing fields. That is going to account for 4 Bbo right off the top if you compare my midcase with your estimate.
Another area in which I include EUR is production from discoveries that have been made, but the projects have not been sanctioned. That accounts for another 3 Bbo difference. The list above includes some of these fields.
I also attribute 1 Bbo to discoveries that have been made, but are currently not economic.
None of the above are going to be in BOEM’s reserve assessment.
I’m not quite sure how to pull 2P reserves out of BOEM’s data, but when I look at their end of 2014 summary of reserves by field, I see a number of deepwater fields where I am quite sure their remaining reserves are less than I would predict (assuming their total reserve number is intended to be EUR).
For example, BOEM’s reserves for Stones is 21 mmbo – I can’t see Shell developing a stand-alone deepwater project for only 21 mmbo.
And BOEM’s Mad Dog reserve number is 30 mmbo. Their is no way BP would go ahead with the Mad Dog 2 project for only 30 mmbo.
I could be wrong with these assessments, but Shell and BP are not dummies.
BOEM’s total reserves for Atlantis are 325 mmbo. Atlantis was the most prolific field in the Gulf in 2015, and it’s current cumulative production is over 260 mmbo and still producing about 90-100 mbopd. I would think it is on track to be at least a 400 mmbo field.
I suspect that if BOEM had the staff to dedicate to it (they are stretched pretty thin), and they looked at the above mentioned fields, they would revise their reserve estimates.
Hi SouthLaGeo,
Shoot me an e-mail if you would like to communicate with Jean Laherrere directly by e-mail rather than do this in a public forum.
EOG inks $2.5 billion deal in shift to low-cost Permian shale
Tue Sep 6, 2016
http://www.reuters.com/article/us-yates-m-a-eog-resources-idUSKCN11C170
EOG Resources Inc said on Tuesday it would buy privately held Yates Petroleum Corp for $2.5 billion in stock and cash, in the latest move by a U.S. energy company to acquire acreage in the Permian Basin, one of the country’s most cost-effective oil fields.
The buyout, which had been under negotiations for months, follows a string of Permian land purchases in the past year by companies that include Pioneer Natural Resources Co and WPX Energy Inc.
With the acquisition, EOG would shift its focus away from the Eagle Ford shale, a more expensive Texas field that had helped the company grow into the largest onshore oil producer in the contiguous United States during the past decade. Much of the Permian acreage is near EOG’s existing well locations and pipeline infrastructure.
“This deal really isn’t about getting bigger. It’s about getting better,” EOG Chief Executive Bill Thomas told investors on a Tuesday conference call after announcing the acquisition.
“We’ll be able to grow oil (production) with less capital and more efficiently than we do now.”
The company plans to start drilling on the new acreage as soon as the deal closes in October and boost capital spending in the Permian in 2017, he said.
EOG will issue 26.06 million shares valued at $2.3 billion and pay $37 million in cash in exchange for Yates, which was founded by Martin Yates, Jr. in New Mexico in 1907 and is run by his descendents.
The deal would raise EOG’s position in the Permian and adjacent plays by more than 200,000 acres, to 574,000 acres, and double its position in the Delaware Basin in southern New Mexico and West Texas.
—————————————
Comment: Companies remain optimistic about the Permian, which is no news.
But it seems that their turn more and more pessimistic about the Eagle Ford.
“This deal really isn’t about getting bigger. It’s about getting better,” – is the main qualification for a CEO to be able to endlessly churn out complete bollocks with a straight face? And is the main qualification for a Reuters or Bloomberg correspondent to be able to listen to and transcribe this meaningless drivel without the least scruple or question?
EOG needs $75 WTI and $4 gas to get to a 30 price earnings ratio at current share price of $94, based on plugging in those numbers, plus assuming an effective income tax rate of 25%.
Those are rough numbers, but feel pretty confident in them, basing those on expenses for first half of 2016.
BTW, they realized $23.17 per BOE for the first six months of 2016 and lost $1.40 per share. There are a little over 547 million shares outstanding.
So, to earn $1.60 per share in first half, 2016, my estimate is they needed about $50 per BOE. They are roughly half oil and half gas and ngls, so that is where I come up with the above amounts. If gas stays lower, oil needs to be higher, etc.
Clueless.
—Note Nicholas Gorgesu-Roegen’s distinction between free energy and bound energy. The first is available to do work. The second is not. http://webpage.pace.edu/dnabirahni/rahnidocs/law802/The%20Entropy%20Law%20and%20the%20Economic%20Problem.pdf
Thanks for that; very good.
The sun will of course be our source of energy long after a few ready generations have eaten all the oil.
Heh Patrick, its been awhile. How’s things in Long White Cloud country?
All good, gettin’ warmer, in a nice-now-but-worrying kind of way.
Hoping we will get a change of gov, or a change in the gov, so we can take our rightful place as a leader in the response to Climate Change… so much potential, and if small countries don’t take risks and try stuff…
Still see Transition happening, but incumbency is a huge drag, takes much longer to change infrastructure heavier than iPhones… especially as the incumbents have their elbows out and the US political ‘system’ is entirely broken. So it goes.
Still lurking here, DC doing a great job, but am sorry that Ron has had to pull back….
Norway – Reducing the cost per barrel by increasing the number of barrels… It’s lucky if you can do that, especially as new discoveries are smaller. But surely it’s a sign of bad planning that they didn’t do that from the start. I’ve been reading that companies are thinking about using automated rigs and robots to make smaller fields profitable…
Statoil – Increasing the value of Johan Sverdrup – August 2016
Phase 1 production capacity is currently estimated at 440,000 barrels of oil per day. The PDO originally estimated the phase 1 production capacity to be between 315,000 and 380,000 barrels of oil per day.
the Johan Sverdrup partners agree on expanding the production capacity on Johan Sverdrup by introducing an extra processing platform on the field centre. This will increase the expected full production capacity on the Johan Sverdrup full field to 660.000 barrels of oil per day.
The capacity increase, together with improved reserve estimate and investment costs, has helped reduce the break-even for the full-field development of Johan Sverdrup to below USD 30 per barrel.
http://www.statoil.com/en/NewsAndMedia/News/2016/Pages/JSaug2016.aspx
oilprice version: http://oilprice.com/Energy/Energy-General/Why-Statoils-25-North-Sea-Break-Even-Claim-Is-A-One-Off.html
ENI’s Goliat oil field thought to be $100 a barrel…
World’s northernmost oil field approved – January 2016
OSLO–A Norwegian regulator on Tuesday formally approved the production vessel at the world’s northernmost oil field, Eni SpA’s Goliat field in Norway’s Barents Sea, which could potentially start pumping next month, over two years delayed and well over budget.
The partners have invested around $6 billion in Goliat, a 52% cost overrun compared with the 2009 plan. With Brent crude trading below $30 a barrel–levels not breached in more than a decade–the Italian oil and gas company is already struggling to make the field economically viable. Analysts have put the break-even point for the field–the point at which it is profitable–at more than $100 a barrel.
http://www.marketwatch.com/story/worlds-northernmost-oil-field-approved-2016-01-19?link=MW_home_latest_news
Norway: ENI’s Goliat oil field to remain shut in at least until 9/9. shut in since 8/26 after power failure. spokesman monday.
For Johan Sverdrup there was always a plan for phase II, but they probably had to wait for drilling results and appraisals. Another factor though might be to ask where their production would come from in 2020 and later if not by expanding that project. They cancelled Bay du Nord (offshore) and delayed Leismar in Canada, seem to have pulled out of GoM, aren’t going anywhere at the moment with West Qurna in Iraq, have a bit going on in Brazil, and in Norway the lowest discovery rate they’ve ever had, only a few small oil tie backs and a couple of gas fields in the next two yeas and Johan Castberg, which is way up north and quite complicated to develop.
Goliat looks like one of those bad luck projects, maybe it’s because it’s in a new area and Eni don’t have the right experience there or they tried to cut quality when the costs ballooned, but sometimes things just go wrong.
Interesting article about a likely supply shortfall in the near future
http://www.businessinsider.com/the-future-of-oil-supply-and-demand-2016-9?r=US&IR=T&IR=T
Deserves to be quoted here in full. I’m not sure I agree with points 9 and 10, but I guess they have to provide a bit of light; everything else is what has been discussed in this blog for the last year and more. (The only thing missing is any comment concerning possible sudden and rapid decline in any OPEC main producer or Russia and the increasing acceleration in China’s decline, there’s also a kind of shrugging indifference, like losing 41 mmbpd by 2040, and therefore all exports, is just another one of those things):
1) Oil’s oversupply problem, which has caused most of the trouble in the markets in recent years will end by 2017, and the market will return to balance.
2)Spare capacity will have shrunk substantially by then “to just 1% of global supply/demand.” This HSBC argues, will make the market more susceptible to disruptions like those seen in Nigeria and Canada in 2016.
3) “Oil demand is still growing by ~1mbd every year, and no central scenarios that we recently assessed see oil demand peaking before 2040.”
4) 81% of the production of liquid oil is already in decline.
5) HSBC sees between 3 and 4.5 million barrels per day of supply disappearing once peak oil production is reached. “In our view a sensible range for average decline rate on post-peak production is 5-7%, equivalent to around 3-4.5mbd of lost production every year.”
6) Based on a simple calculation, HSBC estimates that by 2040, the world will need to find around 40 million barrels of oil per day to keep up with growing demand from emerging economies. That is equivalent to over 4 times the current crude oil output of Saudi Arabia.
7) “Small oilfields typically decline twice as fast as large fields, and the global supply mix relies increasingly on small fields: the typical new oilfield size has fallen from 500-1,000mb 40 years ago to only 75mb this decade.” — This will exacerbate the problem of declining oil fields, and the lack of supply.
8) The amount of new oil discoveries being made is pretty small. HSBC notes that in 2015 the discovery rate for new wells was just 5%, a record low. The discoveries made are also fairly small in size.
9) There is potential for growth in US shale oil, but it currently represents less than 5% of global supply, meaning that it will not be able, single-handedly at least, to address the tumbling global supply HSBC expects.
10) “Step-change improvements in production and drilling efficiency in response to the downturn have masked underlying decline rates at many companies, but the degree to which they can continue to do so is becoming much more limited.” Essentially HSBC argues that companies aren’t improving their efficiency at a quick enough rate, meaning that supply declines will hit them even harder.
Reuters – Spare Capacity – September 8th 2016
Having told the market for many years that they can produce 12.5 million barrels per day if needed, Saudis, including Deputy Crown Prince Mohammed Bin Salman, have said this year they can ramp up supply immediately only to 11.5 million bpd.
Deduct from that figure Riyadh’s current record output of 10.7 million bpd, and that leaves Saudi and effectively global spare capacity at only 0.8 million bpd — the lowest on record and not enough to cover even one major supply outage.
http://mobile.reuters.com/article/idUSL8N1BJ2RS
Is their spare capacity sustainable though, or would they need to pull down reservoir pressures, and/or flare excess gas, and/or risk coning gas at some wells and/or risk getting water fingers or bypassing some sands or any of the other ways that the formations can be messed up if they are produced too quickly? And the older the reservoirs get the more they need careful management.
also from Reuters:
Saudi Arabia’s crude oil production slipped in August to 10.63 million barrels per day (bpd), industry sources said on Thursday, as the OPEC heavyweight leads a drive to revive a global oil output freeze initiative.
Saudi Arabia pumped 10.67 million bpd of crude in July, the highest level in its history, on higher domestic demand in the summer and more exports.
http://www.reuters.com/article/us-saudi-oil-output-idUSKCN11E21N
So, until now, the record Saudi C+C output was 10.67 mb/d. And they were not able to maintain production above 10.6 mb/d for more than 3 months. After Summer peak production/ peak local demand levels Saudi output always drops in the later part of the year.
40,000 a month is about 5% y-o-y decline. They had a period last year with a lot of consecutive months that looked like a similar rate of exponential decay, then Al Shaybah expansion added 250,000 over the summer; but they have nothing much on the cards now until Khurais, another 250,000 expansion, in 2018.
Perhaps it really is
“Twilight in the desert”
The summer peak period next year will probably be the tell bar some other emergency in the oil market.
“Rebels say kill 12 Angolan soldiers in oil region clash”
http://uk.reuters.com/article/uk-angola-war-cabinda-idUKKCN11D13S
Not unexpected I’d say, the rebels are FLEC – Front for the Liberation of the Enclave of Cabinda. Clashes started in late July and appear to be escalating. No impact on oil or gas production yet. Oil production is offshore, the enclave has just under half of Angola’s production associated with it. There may be gas processing, and service and logistic bases there but I don’t know for sure. The Angola LNG project is in Angola proper about 30 miles south of the enclave (a small strip of the Congo and the Congo River lie in between). I think there is certainly some link between this increase in activity and the fall in revenues from oil prices and consequent high inflation in the country. There are existing issues with IOC involvement in new Angola projects because of changes to tax, royalty and local content requirements, plus the undeveloped resources are not cheap. This won’t help.
Suncor is trying to save money because of: low oil prices, higher carbon taxes, big $13.5-billion investment, loss of revenue due to the wild fires…
WSJ – Suncor Energy Seeks Permission to Abandon Some Oil-Sands Assets – By CHESTER DAWSON – Sept. 7, 2016
CALGARY, Alberta— Suncor Energy Inc., Canada’s largest oil producer, is in talks with government officials for permission to “strand,” or abandon, some high cost and greenhouse gas-intensive crude-oil deposits, the company’s chief executive said Wednesday.
The cost of that carbon is becoming a bigger barrier for oil-sands producers, as the province is set to double its so-called carbon tax on them,
http://www.wsj.com/articles/suncor-energy-seeks-permission-to-abandon-some-oil-sands-assets-1473286608
Fort McKay First Nation to put $350M into Suncor oilsands $1billion tank farm
The $13.5-billion Fort Hills project is scheduled to produce first oil in late 2017 and achieve 90 per cent of its planned production capacity of 180,000 barrels per day within 12 months.
http://www.cbc.ca/news/canada/calgary/first-nation-puts-350m-oilsands-project-1.3749640
The Canadian Press – September 7, 2016 – Wildfires that swept through Fort McMurray in May have resulted in the loss of $1 billion in planned capital spending in the oilsands for 2016, according to Alberta’s chief energy economist.
http://calgaryherald.com/business/energy/alberta-estimates-wildfire-put-1-billion-dent-in-2016-oilsands-spending-plans
Thanks for the links!
Suncor Energy announces $1.0 billion medium term note offering
CALGARY, ALBERTA–(Marketwired – Sept. 8, 2016)
http://www.suncor.com/newsroom/news-releases/2085313
http://www.wsj.com/articles/apache-has-high-hopes-for-new-oil-field-discovery-in-texas-1473245702
Apache Corp. said it has discovered the equivalent of at least two billion barrels of oil in a new West Texas field that has the promise to become one of the biggest energy finds of the past decade.
The discovery, which Apache is calling “Alpine High,” is in an area near the Davis Mountains that had been overlooked by geologists and engineers, who believed it would be a poor fit for hydraulic fracturing. It could be worth $8 billion by conservative estimates, or even 10 times more, according to the company. Shares rose by as much as 13% after U.S. markets opened Wednesday.
Reads like hype. WSJ is usually more cynical.
Transocean see a big fall in non-OPEC production this year and predict 7 mmbpd shortfall in supply by 2020.
http://oilpro.com/post/27164/transocean-presents-at-barclays–drillship-demand-must-increase
Despite this being a sales pitch for more drilling I think they are being conservative. They assume only 4% decline rates, but increases to 5 to 6% are more likely as the cuts to brownfield and in field drilling started in 2014 start to be seen more. They see 1 mmbpd per year growth in demand which depends on how the economy performs and possible impacts from rising oil prices.
Hi George,
So you believe between now and 2020 we are likely to see about 5.5% annual decline rates for World Petroleum liquids output, which would be about 5.3 Mb/d (from 3Q2016 levels of 97 Mb/d) over a 12 month period. In my view the 4% decline rate estimate is much more realistic (and if oil prices rise to over $100/b may also be too high), in fact my view is that unless there is a major conflict in the middle east (all out war between KSA and other Sunni nations and Iran and Iraq), annual decline rates are unlikely to be more than 3% per year for World liquid Petroleum output over any 12 month period between now and 2020. One other possibility which would make my WAG wrong is another GFC before 2020, I believe the likelihood of that is low (less than 1 in 10), but the World economy is difficult to forecast.
I think natural decline rates in mature fields will be at least 6% by 2020, compared to Transocean’s figure of 4%. I think Rystad have indicated we already are at around 5 to 6%. The actual decline will depend on what new fields (or revamped old fields) are brought on line. By the second half of 2018 and into 2019 we will be coming to the end of the train of larger projects (say $5 billion plus) that had been approved until the budget cuts started in 2014. There is actually less that 0.5 mmbpd due to start in 2019 and a lot of that is Brazilian which may be delayed. There will not be a lot of quick turn around projects (e.g. 2 year or a small tie back in GoM or North Sea) available then either because of the fall off in recent discoveries. It may be US LTO can ramp up quickly and fill any gap but I have my doubts, the Permian, Bakken and Eagle Ford all seem to be following pretty good logistic curves, and looking at them there is no way to say when or how oil prices changed in the past so I don’t see them changing significantly in response to higher prices in the future (but my confidence level for the accuracy of that prediction is pretty low, the psychology of investors seems to be the biggest influence).
Therefore in the second half of 2018 through 2020 we could drop about 12 mmbdp in decline and only get back 4 mmbpd in new production, based on current approved projects. Brownfield and in-fill drilling might fill the gap, especially in OPEC, but they have been doing that in KSA and some others for a few years now so the marginal gains might not be so good any more.
The Transocean shortfall of 7 mmbpd is well below 3% per year overall decline – they assume 1 mmbpd per year increase in demand to maintain BAU, so it’s only about 3 mmbpd down from now over 4 years which is less than 1% per year.
Hi George,
Sorry, I misunderstood, you are talking about new development needed to replace falling output from developed wells, and you are correct, probably 5.5% average decline in output from producing wells is reasonable, which at 80 Mb/d of C+C output would be 4.4 Mb/d, add in increased demand of about 1.2 Mb/d each year and we need 5.6 Mb/d of new output to be brought online each year just to meet the 81.2 Mb/d of demand in 2016. Before long the lack of investment will catch up and there will be a supply shortfall, this is why I expect oil prices will increase in the future, probably within 12 months. Oil Prices may spike to $120/b and if supply increases as LTO ramps up and deepwater and oil sands projects are sanctioned, oil priced may stabilize for a couple of years at $80 to $100/b (2016$), by 2020 oil prices will continue to rise, maybe in the $120 to $150/b range from 2020-2025. The speed of the transition to alternative types of transportation will determine oil prices after that point as supply will decrease and quantity of demand will be forced to match.
Difficult to predict the outcome, but a bumpy ride is my guess.
Caspian Sea – Reuters is saying that this Kashagan Field is new but it looks like it’s an old one that is being restarted (the photo is dated 2013)….
Reuters – Thu Sep 8, 2016 – Exclusive: New Caspian fields to add at least 200,000 bpd to oil market by year-end
Two major Caspian Sea oil fields scheduled to come on stream this year will together produce at least 200,000 barrels of crude per day (bpd) by the end of 2016, according to industry sources and a loading schedule seen by Reuters.
By the end of next year, according to targets previously announced by the fields’ operators, Kashagan and Filanovsky will between them produce about 500,000 bpd, equivalent to about 0.5 percent of global production.
Production at the long-delayed Kashagan offshore project will start in October this year, according to industry sources who have seen Kazakh Energy Ministry documents on the field.
Output will initially be 75,000 bpd in October, rising to between 150,000 and 180,000 in the November-December period of this year, the sources told Reuters, citing the ministry documents.
Filanovsky will export around 50,000 bpd of CPC blend, a light Caspian crude, between October and December this year, according to a loading schedule, a copy of which was obtained by Reuters.
http://www.reuters.com/article/us-oil-caspian-idUSKCN11E1BZ
This field is restarting in October 2016…
Kazakhstan’s Kashagan Field an offshore sour oil field in the Caspian Sea. (The most expensive energy project in the world)
– officials claimed that after the relaunch Kashagan would reach a commercial output of 70,000-75,000 barrels per day within “a matter of months”.
http://www.intellinews.com/kazakh-oil-field-kashagan-to-resume-production-in-october-says-pm-99835/
https://en.wikipedia.org/wiki/Kashagan_Field
Kashagan only had a brief start of operations in September 2013 and so I guess it could be called new
http://thediplomat.com/2015/06/kazakhstan-kashagan-hopes-are-up/
The pipelines corroded away so they needed to be replaced. This restart will get them back to previous levels at 180,000 bpd; but there is also a phase II, which adds compression and some additional processing to increase capacity by another 170,000 (I think) and that is ahead of schedule by about a year. There is also a phase III under consideration for another 70,000 in 2021 if it goes ahead. Filanovsky is also a second phase on an already operating field if I remember correctly. None of this is unexpected and would be included in Rystad, IHS, and Wood Mac predictions.
Filanovskogo is Lukoil’s field in the Russian part of the North Caspian.
It was initially scheduled to start production in 2015. It’s not the second phase, but is obviously included in estimates by the IEA and energy consulting firms.
In the oil news today
China August crude imports rise to 7.77mbpd, a 4-month high (7.35mbpd in July, 7.48mbpd in June, 7.62mbpd in May, 7.96mbpd in April) Preliminary data from the General Administration of Customs showed Thursday
China completed construction last month of 19 million barrels of new tanks for its state crude oil reserves
Libya offers first crude oil for export from Ras Lanuf port for almost 2 years (capacity 220,000 bpd)
Russian Average Oil Production On Sept 1-7 Close To 11 Million Barrels Per Day. Increase due to restored output at joint ventures. Industry sources to Reuters.
Saudi Arabia’s August crude oil output falls slightly to 10.63 mln bpd vs 10.67 in July – industry source via Reuters
EIA Petroleum Inventories: Crude -14.5M barrels – That’s the 2nd biggest draw in crude inventories (excluding withdrawals from the SPR) since EIA’s first release (1984)
Thought to be due to Hurricane Hermine
Iraq: Kirkuk-Ceyhan pipeline crude exports now at 650kbd, up 250kbd from August. Follows KRG & SOMO agreement. Trader sources via Reuters
People are almost completely ignoring a looming crisis for oil
http://www.businessinsider.com/the-future-of-oil-supply-and-demand-2016-9?r=US&IR=T&IR=T
Will Martin
Sep. 7, 2016, 5:51 AM 52,994 69
oil barrel Reuters/Stefano Rellandini
In the current climate, the vast majority of worry in the oil markets surrounds the huge imbalance in supply and demand in the industry. This is understandable, given that the enormous glut of oil in the markets has pushed prices down from more than $100 around two years ago, to less than $50 right now.
However, in a major new research note, HSBC argues that soon we won’t be worrying about there being too much supply and not enough demand, but rather, things will be the other way round soon enough, and that is going to cause huge problems.
In the report from HSBC staff Kim Fustier, Gordon Gray, Christoffer Gundersen, and Thomas Himboldt argue that given the finite nature of the physical amount of oil in the world, people should really be paying more attention to falling supply in the future, rather than oversupply right now.
Here is the extract from Fustier et al (emphasis ours):
“Given the backdrop of the past two years’ severe oversupply in the global oil market, it’s not surprising that few are discussing the possibility of a future supply squeeze. Indeed, most of the current debate on the long-term outlook for oil seems focused on risks to demand from progress on both the policy and technology fronts.
“Meanwhile, we expect the past two years’ severe crude price weakness to result in a return to balance in the global oil market in 2017. At that stage, we expect global effective spare capacity to fall to as little as 1% of demand. Supply disruptions have had only limited impact on price in 2015-16 due to the global oversupply, but the market will be much more susceptible to interruptions post-2017. In addition, given the almost unprecedented fall in industry investment since 2014, we expect the focus to return to the availability of adequate supply.”
HSBC’s note is more than 50 pages of detailed, thoughtful research on the state of the markets and how the dwindling availability of oil, along with jumping demand over the coming decades will change the world.
But included within the report is a helpful, ten-point summary of the key arguments the bank makes, and what is going on right now. We have summarised the arguments below:
1 Oil’s oversupply problem, which has caused most of the trouble in the markets in recent years will end by 2017, and the market will return to balance.
2 Spare capacity will have shrunk substantially by then “to just 1% of global supply/demand.” This HSBC argues, will make the market more susceptible to disruptions like those seen in Nigeria and Canada in 2016.
3 “Oil demand is still growing by ~1mbd every year, and no central scenarios that we recently assessed see oil demand peaking before 2040.”
4 81% of the production of liquid oil is already in decline.
5 HSBC sees between 3 and 4.5 million barrels per day of supply disappearing once peak oil production is reached. “In our view a sensible range for average decline rate on post-peak production is 5-7%, equivalent to around 3-4.5mbd of lost production every year.”
6 Based on a simple calculation, HSBC estimates that by 2040, the world will need to find around 40 million barrels of oil per day to keep up with growing demand from emerging economies. That is equivalent to over 4 times the current crude oil output of Saudi Arabia.
7 “Small oilfields typically decline twice as fast as large fields, and the global supply mix relies increasingly on small fields: the typical new oilfield size has fallen from 500-1,000mb 40 years ago to only 75mb this decade.” — This will exacerbate the problem of declining oil fields, and the lack of supply.
8 The amount of new oil discoveries being made is pretty small. HSBC notes that in 2015 the discovery rate for new wells was just 5%, a record low. The discoveries made are also fairly small in size.
9 There is potential for growth in US shale oil, but it currently represents less than 5% of global supply, meaning that it will not be able, single-handedly at least, to address the tumbling global supply HSBC expects.
10 “Step-change improvements in production and drilling efficiency in response to the downturn have masked underlying decline rates at many companies, but the degree to which they can continue to do so is becoming much more limited.” Essentially HSBC argues that companies aren’t improving their efficiency at a quick enough rate, meaning that supply declines will hit them even harder.
Here is the chart showing the decline in production post-peak:
(for some reason the chart didn’t copy but it is basically a declining line)
oil peak production HSBC
All these concerns combined, HSBC argues, means that we should be less worried about the current tilting of the oil market to oversupply, and more towards the coming decline in supplies. It may not hit us for a while, but it is a looming crisis that the oil industry must face.
Dana Gardiner,
Thanks for this.
For all: This just in–HSBC has been reading Jeffrey Brown, Shallow Sand, and Mike Shellman. You heard it here first.
Why do US crude oil inventories, which are likely around 8-12% of world wide inventories, matter so much to world wide crude oil prices?
I’ve looked to see if any other large regions of the world produce weekly data like this, like the European Union but I’ve not found anything yet. Perhaps this is all there is for people to focus on?
What % of US storage is owned by OPEC member states?
How much oil has the US been importing from OPEC member states in 2015-16 v prior years?
How much oil have OPEC member states had in storage in 2015-16 v prior years.
Same question with regard to Russia?
Shallow,
Are you suggesting that the OPEC counties/Saudi,have been stacking the books by sending their excess exports to the US, as they know these are the only slockpiles that get counted? /sarc
Idk. Motiva refines 1.1 million per day. Not sure how much storage they control?
OPEC oil exports for August
ClipperData – Before we revisit production freeze prognostications, let us check on the scores on the doors for OPEC oil exports for August…and they are once again at a new record. Funny that:
http://blog.clipperdata.com/large-oil-draw-surprises-market
Bakken drilling rig count seem to be on quite a rise this week. Up to 37.
BH should be interesting tomorrow.
Toolpush. Been wondering if US shale drillers have some inside info on OPEC and Russia actions.
Wall street has bid LTO shares up to 52 week highs, acreage is selling for higher than it did in 2013-14.
Many seem to be betting that sub $50 oil wont be around much longer. Who knows? Very political stuff, has been since US became a net crude importer.
WTI traded in $10-12 range in late 1998-early 1999. Cut occurred in 3/99. Price doubled in six months, and stayed strong until late 2001 (9/11/01).
WTI traded in mid $30s-low $40s late 2008-early 2009. Cut also began 3/09. Price again roughly doubled in six months, stayed strong until late 2014.
This time, oil has rallied greatly from lows, but is still less than half 2011-14 levels.
I still maintain OPEC (to a lesser extent Russia) has considerable control. How much capital will it take US shale to add 1 million bopd at this point? How about 2 million bopd?
Two year anniversary of John Kerry meeting in Saudi is Sunday, 9/11.
Recall Saudi sources that oil would be low for two years, shortly after Thanksgiving, 2014 meeting.
However, they were calling for $60, not $40 or lower.
To matter be worse, Russians now project budget and economic performance till 2020 on average price on Brent $42-43.
I see big problems in oil market after 2017. During 2017 i expect back on line Libya, Iran and Nigeria, it will added 1.5-1.7 mb/d in supply, but supply will only balance market. After that, there will be no political disruption of oil supply. First time after 50 years and Arab oil embargo(Iran revolution, Iran-Iraq war, First Gulf war, Iraq sanctions, Second Iraq war, Iraq turmoil, and Libya war 2011) there will be no political disruptions in oil supply. So, you can’t just do regime change and open oil spigots. Market will be very sensitive for disruptions in supply, with very low spare capacity in OPEC.
Also, i expect oil freeze deal now, but in june 2017, deal will be dead.
Standing Rock Sioux Tribe urges calm as National Guard called in before pipeline ruling
North Dakota governor brings in more police, calls up National Guard ahead of court decision
By Tim Fontaine, CBC News Posted: Sep 08, 2016 7:54 PM ET
Dakota Pipeline Fight Is Sioux Tribe’s Cry For Justice
he Standing Rock Sioux, one of the nation’s poorest communities, fear the pipeline’s threat to their water and are angry at government’s blind eye to their plight.
By Phil McKenna, Inside Climate News, September 8, 2016
Brings to mind an image that sticks in my head to this day that was in Marc Reisner’s Cadillac Desert, which I read long ago.
George Gillette, chairman of the Fort Berthold Indian Tribal Council weeps as he watches Secretary of the Interior J. A. Krug sign away the tribe’s rights to the Missouri River and the loss of 700 miles of the most fertile of tribal lands on May 20, 1948. Krug is signing a contract that turned over 155,000 of the reservation in North Dakota for the Garrison Dam and Reservoir project. In a prepared statement, Gillete said: “The members of the Tribal Council sign this contract with heavy hearts. Right now the future does not look good to us.”
Seemingly unstated in this ongoing dispute is the fact the DAPL will run for 40 miles -including crossing the river – adjacent to the Northern Border Pipeline, a large natgas pipeline that was installed in 1982.
The Northern Border gas pipeline that you mentioned is called that because it crosses the Missouri River at the northern border of the Standing Rock Reservation?
The original route for the proposed pipeline crossed the Missouri River further north, upstream of Bismarck, the state capital, but the route was changed when the company said it found that the new route near Standing Rock was shorter and less costly. Also listed as a concern was the close proximity to wells providing Bismarck’s drinking water supply.
“A statement like that says they don’t believe it’s safe, so they wanted it moved to the lowest impact area which they consider to be the reservation,” Willard said. “Well, we’re just as important. My kids drink this water.”
If you haven’t read it Cadillac Desert is a must read.
aws,
The judge allowed the construction and a few hours later the White House stopped it.
Thanks Synapsid.
U.S. government seeks to halt North Dakota pipeline construction
Federal agencies ask pipeline company to ‘voluntarily pause’ construction
CBC News Posted: Sep 09, 2016 2:52 PM ET
Fort Berthold Reservation consists of the Three Affiliated Tribes, the Mandan, Hidatsa, and the Arikara. That’s where the oil is, not at Standing Rock. If oil was on the Standing Rock Reservation, the pipeline would have been constructed, no problemo.
The Sioux are not among the Three Affiliated Tribes. The Mandan lived on the river banks of the Missouri. Lewis and Clark had dinner with them.
The Sioux are the Plains Indians. The Treaty of 1851 had a land area designated for the Sioux Nation west of the Missouri from the western half of Nebraska to Wyoming and into Montana, the northern border was at the Heart River just south of Bismarck, ND. All of the land west of the Missouri in South Dakota was part of the Sioux Nation including the Black Hills.
The Sioux raided Mandan, Hidatsa and Arikara encampments on a regular basis way back when way out west.
The Standing Rock Sioux are short land from what was originally agreed by treaty. On June 25, 1876, General Custer entered the scene, Crazy Horse was at the Battle of The Little Bighorn to give Custer a haircut. A year later, Crazy Horse was bayoneted by US Army troops at Standing Rock.
The Sioux were not to attack settlers crossing Sioux Nation lands, but the Sioux did attack. Broke the treaty, the Sioux Nation was reduced to Standing Rock and Pine Ridge in South Dakota.
Now, there are too many people living on what once was Sioux Nation land these days, no turning back. 12,000 oil wells, roads, highways, communities, farmland, ranch land, etc now dot what was once the Sioux Nation. Of course, the Sioux were extirpated from Minnesota too.
The Sioux attacked the town of New Ulm, Minnesota in 1854.
New Ulm is the home of Schell’s Brewery, however, the Sioux did not attack and burn the brewery, August Schell was supplying the Sioux with firewater. The Sioux weren’t about to ruin their source of alcoholic beverages. Cheers!
You can blame Abraham Lincoln and the Homestead Act, people from Europe rode trains from Chicago to Minnesota then further west after that. Prospectors, miners, the whole enchilada, came out of no where to settle the western United States.
Progressed to the post-modern era and here we are, oil, coal, electricity, nobody is going to give up a good thing.
That’s the way it goes moving west.
It does seem we are all to willing to make excuses for inequality.
My heart is with the Sioux but my head is telling me that the life ain’t fair and the little guys lose out, long term, when they have something the larger public wants. Some of my own family members were kicked off their land to create a small local portion of the national park system.
In this case the land is still there, held in public trust, for now at least. But I don’t have any trouble imagining a time when it might be turned over to some corporation to be run as a resort, or the timber on it cut, if the cards of history fall wrong.
One thing is for sure, none of it will ever be under a reservoir, it’s all mountain top, lol.
I have a new update on oil & gas production in the Marcellus (PA) and Utica (OH), here.
Baker Hughs Rig Count – the change this week is mostly due to the GoM + 8
8/26/2016 – Gulf Of Mexico: 17
9/2/2016 – Gulf Of Mexico: 10
9/9/2016 – Gulf Of Mexico: 18
Permian -2 to 200
Another supply/demand balance chart, this time from Morgan Stanley. They don’t see the market balancing until the next next summer. As I don’t have the whole report I don’t know if they list their assumptions.
Chart on Twitter: https://pbs.twimg.com/media/Cr7E0I8UkAAfx8x.jpg
Baker Hughs – International Rig Count for August 2016 – very little change from last month
sorry for the double post – I did delete this
Baker Hughs Rig Count – the change in the count this week is mostly due to the GoM +8
8/26/2016 – Gulf Of Mexico: 17
9/2/2016 – Gulf Of Mexico: 10
9/9/2016 – Gulf Of Mexico: 18
Permian -2 to 200
Another supply/demand balance chart, this time from Morgan Stanley. They don’t see the market balancing until next summer. As I don’t have the whole report I don’t know if they list their assumptions.
Chart on Twitter: https://pbs.twimg.com/media/Cr7E0I8UkAAfx8x.jpg
Baker Hughs – International Rig Count for August 2016 – very little change from last month
Nice chart. Looks like just the rigs that were moved or shut down for the hurricane returned, not much else changed. Maybe the Permian excitement has cooled off a bit. Is Canada falling more than expected based on seasonal changes – it certainly looks like it?
Internationally Venezuela added rigs – how?
(P.S. Hughes is with an e as in Howard Hughes)
Int. Rig Count – I was thinking that I should wait until something happens before I post a chart, but it does show how little activity there is around the world an these prices.
The chart didn’t update properly, there’s a green triangle missing, here is a fixed version
https://s13.postimg.io/gt5vk7uvb/Baker_Hughes_International_Rig_Count_for_Augus.png
The Jakarta Post – Oil, gas sector continues to look bleak
Tue, September 6 2016
http://www.thejakartapost.com/news/2016/09/06/oil-gas-sector-continues-to-look-bleak.html
Marcellus and Utica are up a few. Last week was the same. I feel this may be the beginning of a trend, as the gas players run down their DUCs and new pipelines come on stream before the winter.
Yair . . .
O/T to Hell and gone but an oilman on here may care to offer on opinion. . . I’m researching for a book.
The question . . . . Is directional drilling accurate enough to target a swimming pool at a mansion (say) two thousand yards from the rig?
Thanks if you can help. (grins)
Cheers.
Yes. In 1999 we put about 4000 feet of 36-inch-diameter natural gas pipeline under the Minnesota River and nearly 6000 feet under the Mississippi River using horizontal directional drilling for construction of the Alliance Pipeline. The initial bore was made with a six-inch drill and then reamed with successively larger bits to a final diameter of about 50 inches. Because in both crossings the bore was made through unconsolidated sediments the bore hole was kept open with pressurized drilling mud. The length of pipe needed for the crossing was welded up and then pulled through the bore in a single pull. The pipe was installed 20 to 30 feet below the bottom of the river. Because the initial bore could be steered by the operator (as can be done now with fracked shale wells) the drill bit emerged on the far side of the river in both cases within 5 feet of the target.
scrub puller,
Even though I’m not a driller, my initial thoughts are that yes, a good directional driller could hit a swimming pool (assuming a mansion has a pretty big pool) 6000′ away. I strongly suspect with today’s real time directional drilling technology they could even do better than that – at least, you would get directional data that says you hit the target. I’ve been involved with many directional wells with the target depths greater than 20,000′, and the drillers easily hit a 200′ x 200′ target box, in fact, they would have hit a 50’x 50′ target.
The thing I’m not to knowledgeable about is the error bar around those directional data measurements – in other words, even though the directional survey says you hit the target spot on, is the error bar large enough that you may actually be outside the target?
Yair . . . .
Thanks for reply SouthLaGeo.
I write weird stuff at times and the query was prompted by a short clip I saw of a drill bit emerging from the ground . . . reasons unknown but it looked impressive. In my twisted mind there arose notions of “payback” and “revenge”. (grins again)
Cheers.
Srubbie,
The best example I can come up on how accurate current directional drilling was when I was in Russia, we had drilled a well vertically to around 2500m. We then started a bend to the horizontal and drilled to the landing depth. We pulled out of the hole to the 3 3/8 casing shoe and ran back in to ensure the hole was clean for the casing run. We hit a ledge and started drilling new hole, and could not get back into the hole we had originally drilled.
Conventional though was, pump cement, kick off and re-drill a new hole. Logically it was going to take us a week just to set up for the job. ship in new mud, drilling tools etc. The directional driller begged to be given a chance to continue drilling and he would find the old hole. He was given the chance as we had nothing to loose. A day later the 12 1/4″ bit found the 12 1/4″ hole over 2500m down in the matrix of rock. A real needle in the haystack.
It was celebrations all around and certainly raised my opinions on the accuracy of the drilling tools available today.
Check out extended reach drilling at Sakhalin (13 km away) or Troll oil layer (laterals had to follow 8m reservoir layer for a long way) or Chevron Congo crossing (two wells met in the middle under the river) or drilling any relief well for a blowout like Macondo which has to intersect the original well bore.
Targeting might be the easy part – drill strings don’t bend very sharply (it’s called a sail angle – targets further out horizontally need to be deeper as well) and I’ve never heard of them going uphill properly, but all things are possible I guess.
George,
Fish hook holes are a reality. You may need to run some HWDP up string to get the force on the bit, and in my experience, rotation was required to up or down when off “bottom”. That was a 7000m well with a TVD of around 2600m.
There is a famous photo where the drill bit is poking out of the ground, and the rig in the back ground a mile or so away.
Looks like a total screw up, but I have been told it could be to calibrate the tools. What ever the reason, it is visual proof that drill bit can drill up hill.
Shell took a kick in a fish hook well, it made an interesting exercise at well control school.
Yair . . .
Thanks fellers, I really appreciate the replies . . . I too wondered about the going up hill part.
I can think of no other place where I could have got such quick answers to such an oddball question.
Cheers.
So are you going to go now and drain someone’s pool from a mile away? ‘u^
https://www.youtube.com/watch?v=1HiBeLRsJoM
Talk in background “no more than 15 feet to the left”
Yep, that is the one. But I am sure the Russians didn’t say 15ft to the left. 5 metres, maybe.
It certainly was a planned event, or otherwise the camera wouldn’t have been to record it for all to see.
For all,
An article today at OilPrice.com on Argentina saying it makes sense to consider working jointly with Britain on exploration for oil near the Falklands.
This article goes into some detail about the recent increase in earthquake activity in Oklahoma, etc.
http://fivethirtyeight.com/features/how-the-oil-and-gas-industry-awakened-oklahomas-sleeping-fault-lines/
I’m not sure how Pemex is run. They’ve made billions of dollars losses for 13 consecutive quarters (even when oil price was high) yet seem to continue to pay a lot of taxes which they then get back partially to cover the loss. However some of that is about to change:
“Mexico to slash Pemex budget”
http://www.upstreamonline.com/live/1443626/mexico-to-slash-pemex-budget
“Of the cuts, 100 billion pesos fall on Pemex, which is already facing a funding sueeze and has racked up multi-billion dollar losses for years. Since the government ended its oil and gas monopoly nearly three years ago, Pemex has faced stiff competition from the private sector.”
“Currently running at some 2.16 million barrels per day, Mexican oil production will slip to an average of 1.93 million bpd in 2017, the budget forecasts. The last time Mexican crude output fell below 2 million bpd was in 1980.”
(That’s an 11% drop, and notice the low number is a yearly average, daily production could be down around 1.8 – there’s no quick turn around from there when budgets are being slashed and I predict a possibility of 20% y-o-y drop in KMZ at any time).
The Platts version of the story includes a forecast for exports…
Exports of crude, according to the document sent to the Congress, are expected to be 771,000 b/d next year, also the lowest since 1980. So far in 2016, exports have averaged 1.14 million b/d.
http://www.platts.com/latest-news/oil/mexicocity/pemex-spending-crude-output-exports-all-slashed-21482947?
Mazama (BP) has Mex consumption at just under 2 mbpd and the decline from 2014 ain’t much at all. If production goes much under 2 there won’t be exports.
The mazama thing is probably all liquids.
Mexico matters. It would be a lot easier to prevent oil coming to the US by force if it comes from farther away.
Here are Pemex’s figures if they’re of any interest
with Baker Hughes land+offshore rig count
JODI closing stocks: https://s21.postimg.org/9gg234ozb/Mexico_JODI_Closing_Stocks_for_June.png
Is there data for their refined products import to give a net export – I think it will be trending to zero in a couple of years.
Yes it looks like there is, I’ll have another look next time…
Volume of Imports of Refined Products,Natural Gas and Petrochemicals
plus
Volume of Exports of Refined Products, Natural Gas and Petrochemicals
http://www.pemex.com/en/investors/publications/Paginas/petroleum-statistics.aspx
I guess that I should have pointed out that, Exports (on the chart)= Crude Oil Exports. I cannot find a value for crude oil imports?
Baker Hughes – Worldwide Rig Count for August 2016 – Totals
The decrease in rig count since July 2014. July was the last month that WTI averaged over $100 for the month.
Canada -63%
U.S.A -74%
Total International -32%
The decrease in rig count since July 2014. July was the last month that WTI averaged over $100 for the month.
Latin America -54%
Europe -37%
Africa -41%
Middle East -12%
Asia Pacific -23%
Permian -66%
Libya in the news – Forces loyal to Libya’s Haftar say they captured Ras Lanuf and Es Sider ports from fighters loyal to UN-backed government…
https://www.yahoo.com/news/libya-generals-forces-seize-key-oil-terminals-103240417.html
Went over to Mr. Peabody’s laboratory of history, the Wayback Machine took me to the future! lol
Future Global Crude Oil Supply
L. F. Ivanhoe
Inexpensive crude oil fuels the world’s economies and armies. In 1986, for the first time, the global production of crude oil and natural gas liquids exceeded new reserves added. Proved oil reserves at the end of 1985 stood at 707.6 billion bbl (BBO), but declined to 703.1 BBO by the end of 1986. The 1986 reserve decrease–4.5 BBO–was 20.4% of total global production of 22.0 BBO. This handwriting on the wall is very bad news.
The world’s recoverable crude oil and natural gas liquids discovered through 1985 totaled 1,258 BBO, including cumulative production of 551 BBO and 707 BBO of reserves. At current production rates, half of all discovered oil will have been burned up by 1989. Timing of the end of our oil age can be extrapolated from a modified “Hubbert curve,” with future production resembling a mirror image of past production. The watershed beginning of the inevitable decline in global crude oil supplies can be expected in the late 1990s, although the date may be over 30 years later in some “super-oily” Organization of Petroleum Exporting Countries (OPEC).
Clearly the day of reckoning will be postponed by any new oil discoveries. These will probably be distributed much as are the present global reserves (e.g., 68% OPEC; 11% USSR and China; 21% rest of world). Of this, 56% will be in the Persian Gulf area. “Giant” fields (more than 0.5 BBO reserves) contain 75% of the world’s reserves. Discoveries of oil in the globe’s 320 known giant fields peaked at 125 BBO during the period 1961-1965, after which giant field discoveries plunged to only 10 BBO during 1981-1985. Henceforth, we should expect to find few giant whales (but many minnows) in the non-OPEC world’s fished-out basins.
Every new field will help as global crude oil supplies dwindle. Therefore, it is essential that all large prospects outside the Persian Gulf be tested promptly, so the oil-importing nations will know what size of non-OPEC reserves are available.
http://www.searchanddiscovery.com/abstracts/html/1988/sepm/abstracts/0384.htm
Purdy doggone frightening, another nightmare nobody needs.
December 2020 futures has contracts at 54.48 usd.
http://www.cmegroup.com/trading/energy/crude-oil/light-sweet-crude.html
At least we know that somebody knows that there will be some oil available into December of 2020.
Very comforting to know, a relief.
However, oil consumption at a rate of 34,675,000,000 barrels per year, in 33 years, there won’t be much left. Then it will be time to panic, until then, it will be business as usual.
Still waiting for the bottom in Texas oil completions activity. Are we there yet, or do we still need a higher oil price?
Texas RRC data for August (still waiting for the well count update)
EIA production data for June
OPEC MOMR – September Edition
Total OPEC (secondary sources) August 2016: 33,237 kb/b (down -23 from July 2016: 33,260 kb/d)
OPEC expects non-OPEC oil supply to grow slightly in 2017 mainly due to the early start of Kashagan…
World Oil Supply
Non-OPEC oil supply in 2016 is now expected to contract by 0.61 mb/d, following an upward revision of 0.18 mb/d from the August MOMR to average 56.32 mb/d. This has been mainly due to a lower-than-expected decline in US tight oil and a better-than- expected performance in Norway, as well as the early start-up of Kashagan field in Kazakhstan. In 2017, non-OPEC supply was revised up by 0.35 mb/d to show growth of 0.20 mb/d to average of 56.52 mb/d, mainly due to new production from Kashagan. OPEC NGLs are expected to average 6.43 mb/d in 2017, an increase of 0.15 mb/d over the current year.
OPEC MOMR – August Edition
In 2017, non-OPEC supply is expected to decline by 0.15 mb/d, following a downward revision of 40 tb/d.
Creditors lose historic sums in oil bankruptcies, Moody’s says:
“For the lenders that bankrolled the shale boom, the oil-market crash may leave as much financial wreckage behind as the devastating telecom bust in the early 2000s, Moody’s Investors Service said.
“On average, banks and bond investors have recovered only about $1 of every $5 they poured into the U.S. oil companies that eventually went bankrupt in 2015, according to the credit rating agency.
“That amount is about a third of the money creditors historically have pulled out of drillers who default on their debt. It’s slightly less than investors recovered from bankrupt telecom firms in 2002, and “can only be described as catastrophic,” the credit ratings agency said in a new report released Monday.”
http://fuelfix.com/blog/2016/09/12/creditors-lose-historic-sums-in-oil-bankruptcies-moodys-says/
OPEC monthly oil report is out.
Down 23,000 over all.
Iran up 22000, Saudi up 28000, Nigeria down 51000, Venezuela down 12000, Libya down 21000, Ecuador down 6000.
The EIA have added a DUC data section to their Drilling Productivity Report…
DUCs, Tab 3: http://www.eia.gov/petroleum/drilling/#tabs-summary-3
with a data file for download, chart for illustration…
DUC Inventory for Natural Gas Regions: Marcellus + Utica + Haynesville
IEA joining Opec in seeing a prolonged supply surplus
They assume that all of the outages come back to the market.
They give a tiny free chart
(free highlights) https://www.iea.org/oilmarketreport/omrpublic/
Nigerian crude outages should be back in the market by October. Accounting for half a million barrels a day…
ExxonMobil offers October loading of Nigerian Qua Iboe crude oil for the first time since July force majeure – Reuters sources (Qua Iboe exports 250,000 bpd)
Shell Nigeria lifts force majeure on Bonny Light – Reuters Sept 6th 2016
The Forcados terminal can typically export 200,000 barrels a day
I found a bigger chart
It DOES NOT RUN ON OIL.
The Chevy BOLT will be on sale this fall with an EPA rated range of 238 miles, according to the morning news.
If it turns out that the batteries used in electric cars really and truly do last a long time and that the materials in them can be easily recycled, then the worst effects of peak oil may be delayed quite a while.
Electric cars could be selling like ice water in hell within five or ten years. Ditto plug in hybrids, given that a plug in hybrid battery need provide only fifty miles or so of range to reduce the typical car owners gasoline consumption by as much as ninety percent if she is diligent about recharging every night.
SHE will be the relevant pronoun, at first, most likely. Well educated, well paid, environmentally conscious, etc, but not a car nut as such, and so not willing to pay six figures for a car.
I doubt if the rise of the electric car will have any easily discernible impact on the market for oil within ten years, and by then depletion may remove oil from the market as fast as electric cars reduce demand for it anyway, so our hands on guys probably won’t go without work, unless THEIR wells run dry.
http://uk.reuters.com/article/china-crude-output-idUKL3N1BP1IP
China output decline might be accelerating. I notice Reuters and Bloomberg and to some extent EIA and IEA don’t seem to be allowed to use the words depletion or decline or exhaustion, it’s always ‘maturing fields shut in’ or words to that effect.
It sounds like China’s aging oilfields need at least $60 a barrel which is the same figure often quoted for the North Sea…
“China’s crude output won’t see an apparent rebound unless Brent recovers to $60 a barrel level, as most of China’s aging oilfields can’t make a profit below this price,” Tian said.
http://www.bloomberg.com/news/articles/2016-09-13/china-oil-output-drops-to-6-year-low-as-state-giants-shut-fields
I don’t think they will rebound at any price – they have used horizontal wells at maximum height in the formation with thermal and polymer flood water injection, and lots of rigs to do in fill drilling, to maintain production over the last few years. Once water hits the producers there isn’t that much more you can do, 20% decline rates for a couple of years are not unusual on water flood with horizontal wells. They haven’t got any large new fields to bring on line no matter what the spokespersons for the main companies have to say because they haven’t found any major new oil fields.