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US Oil Output Jumps To Record High, 10.47 million bbl/d

Production

U.S. crude oil production jumped 215,000 barrels per day (bbl/d) to 10.47 million bbl/d in March, the highest on record, the Energy Information Administration (EIA) said in a monthly report on May 31.

Production in Texas rose by 4% to almost 4.2 million bbl/d, a record high based on the data going back to 2005. The Permian Basin, which stretches across West Texas and eastern New Mexico, is the largest U.S. oil field.

Output from North Dakota held around 1.2 million bbl/d, while output in the federal Gulf of Mexico declined 1.1% to 1.7 million bbl/d.

The agency also revised February oil production down by 5,000 bbl/d to 10.26 million bbl/d.

U.S. crude oil output rose above 10 million bbl/d late last year for the first time since the 1970s, overtaking top oil exporter Saudi Arabia, but it still lags behind top producer Russia, which pumps just below 11 million bbl/d.

U.S. oil imports from Venezuela increased to 17.3 million bbl in March from 13.21 bbl in February. Last month’s level was close to the all-time low of 13.20 million bbl, reported in January 2003. OPEC-member Venezuela’s oil output has declined amid political unrest.

Gasoline demand in March was 9.4 million bbl/d, up 1%, or 94,000 bbl/d, from a year earlier, according to the report. At the same time, gasoline exports rose to 951,000 bbl/d, up 361,000 bbl/d from a year earlier.

Demand for distillate fuels, including diesel and heating oil was 4.2 million bbl/d, up 0.4%, or 15,000 bbl/d, from a year earlier. Distillate fuel exports were 1.15 million bbl/d in the month, down about 12,000 bbl/d from a year earlier.

U.S. natural gas production in the Lower 48 states rose to an all-time high of 88.8 billion cubic feet per day (Bcf/d) in March, up from the prior record of 87.7 Bcf/d in February, according to EIA’s 914 production report.

Output in Texas, the nation’s largest gas producer, increased 1.3% in March to 22.7 Bcf/d, the most since April 2016.

In Pennsylvania, the second biggest gas producing state, production dipped to 16.4 Bcf/d in March, down 0.6% from February’s record high of 16.5 Bcf/d. That compares with output of 14.8 Bcf/d in March 2017.

The U.S. has been the world’s biggest producer of gas since 2009, ahead of Russia.

oil gas investor



40 Comments on "US Oil Output Jumps To Record High, 10.47 million bbl/d"

  1. Duncan Idaho on Fri, 1st Jun 2018 10:56 am 

    Explaining The Double Digit WTI Discount

    https://oilprice.com/Energy/Oil-Prices/Explaining-The-Double-Digit-WTI-Discount.html

  2. Outcast_Searcher on Fri, 1st Jun 2018 11:41 am 

    Yes Duncan, let’s pretend that market adjustments somehow change the fact of record US production, if that record interferes with the meme of constant doom. Hint: markets adjusting to changing supply and demand is a good thing.

  3. MASTERMIND on Fri, 1st Jun 2018 11:53 am 

    Fox News proposes blasting down school walls with cannons in event of school shootings..

    https://imgur.com/a/6WWGsZt

  4. MASTERMIND on Fri, 1st Jun 2018 12:26 pm 

    Outcast_Searcher

    It will take 2,500 new wells a year just to sustain output of 1 million barrels a day in North Dakota’s Bakken shale, according to the Paris-based International Energy Agency. Iraq could do the same with 60 conventional wells. Ultra-light oil makes poor-quality gasoline that has to be put through an additional process (and cost) called catalytic reforming that boosts octane to sales specifications. And most crucial is that this light oil lacks the middle distillates needed to produce diesel and jet fuel. Those are the three biggest refined product markets so ultra-light oil has a lot going against it.
    Right now, the main approach is to blend the ultra-light with heavier grades of oil to create a mixture that can be put into refineries.

    This has created high demand for heavier oil (20-30 API gravity). The main sources for the U.S. are deep-water Gulf of Mexico, Mexico, Venezuela and Canada. Much of this heavy oil has problems of its own for refiners especially the syn-crude from Canada and Venezuela that contains large volumes of bitumen that requires a special kind of refinery (“cokers”) that can deal with the carbon and sell it as petroleum coke. Most of these refineries are in the Midwest (Chicago area mostly). The deep water GOM crude contains considerable sulphur that must be removed before refining further. As you can see, it is a complex problem. It reflects the fundamental premise of Peak Oil—namely, that we have run out of cheap oil.

    https://www.bloomberg.com/news/articles/2014-02-27/dream-of-u-s-oil-independence-slams-against-shale-costs
    https://imgur.com/a/t7ulB

  5. Duncan Idaho on Fri, 1st Jun 2018 2:42 pm 

    Yes Duncan, let’s pretend that market adjustments somehow change the fact of record US production
    Yea, and as soon as they can make a profit–
    https://www.ft.com/content/c43b55c4-bb2d-11e7-8c12-5661783e5589

  6. Boat on Fri, 1st Jun 2018 6:03 pm 

    Mm

    Anyone can take legacy wells pumping almost nothing and create an impression. Chess boy is one of them. The drilling productivity report can tell a story that shows new wells almost tripiling new well production from just three years ago. Tech folks. Truth is they are not drilling as many new wells….
    But if you watch these things you would see Drilling counts rise slowely.
    These mm characters are full of short on oil type shyt. Playing with stats for God’s knows what reason. Just another peckerhead.

  7. MASTERMIND on Fri, 1st Jun 2018 6:47 pm 

    Duncan

    The shale industry is in business to get money, not make any..

  8. MASTERMIND on Fri, 1st Jun 2018 7:06 pm 

    Civilization will be killed off in one of these three ways, scientists say

    https://nypost.com/2018/06/01/civilization-will-end-in-one-of-three-incredibly-bad-ways/

  9. Anonymous on Sat, 2nd Jun 2018 4:05 am 

    I just saw that Deffeyes died last November. Was there an article or thread on this site talking about it?

  10. Duncan Idaho on Sat, 2nd Jun 2018 3:43 pm 

    10.5? The US uses around 20.
    We have a ways to go—-

  11. Davy on Sat, 2nd Jun 2018 4:11 pm 

    Idaho, some of that difference is exported as final product.

  12. rockman on Sat, 2nd Jun 2018 4:13 pm 

    None of these different oils are selling at a “discount”. They are selling at their market values. No EU refinery is buying WTI oil delivered to its gate at a “discount” to what it is paying for Brent oil. First, the US is only exporting about 16% of its domestic production according to the EIA. Second, according to the EIA the majority of US oil exports are condensate/light oil (and not WTI) which countries, such as Canada, are willing to pay WTI prices PLUS transportation costs to meet their requirement to blend with their heavy oils for refining and for producing “dilbit” so its heavy crap can be exported via pipelines.

    The article is very confusing…perhaps intentionally so. OK, so the Chinese can buy WTI benchmarked oil for $X/bbl. So what? IOW the Chinese can buy all the oil they want priced at the WTI benchmark…sitting in storage tanks in Cushing, OK. How does that do them any good?

    Folks do understand that the WTI price thrown around is for delivery of oil to Cushing, right? That price isn’t what it would cost a refinery in China to see a bbl of WTI pass through it gate, right? First, that oil has to be pipelined to a Gulf Coast export terminal…for a fee, of course. It then has to be stored in a tank until enough is amassed for a tanker load…for a fee, of course. It then has to be pumped into a tankers and shipped half way around the world…for a fee, of course. And then when the ship reaches China the oil has to be pumped into storage tanks…for a fee, of course. And then the oil has to be pipelined to the refinery…for a fee, of course.

    Of course, the Chinese could buy oil already sitting in storage tanks at an export terminal on the Texas coast. But that oil is priced on the WTI benchmark price PLUS the transport cost to get it to the export terminal PLUS the profit margin built in by the company that paid to have the oil delivered to the terminal. And, of course, the company that built those terminal storage tanks didn’t do it as a charity.

    As far as comparing the WTI benchmark price to the Brent benchmark price or any other benchmark price I don’t get the point. So Brent is selling for more then oil. WTI oil sitting in a storage tank in Cushing, OK. OK now ship WTI Cushing oil half way around the world to a terminal where North Sea Brent is being delivered and bought by refineries. Does anyone think those bbls of WTI would cost an EU refinery the same price it would cost to buy the WTI oil sitting in a tank in Cushing, OK.?

    Paying less for a bbl of WTI then for a bbl of Brent when that WTI oil is sitting in the middle of Oklahoma where its of no value to an EU refinery is not buying that oil at a “discount”…it’s pissing away the refinery’s money.

  13. Duncan Idaho on Sat, 2nd Jun 2018 4:22 pm 

    The US averages 19.69 million barrels per day in use.
    So subtract that from 20—–

  14. rockman on Sat, 2nd Jun 2018 4:25 pm 

    Davy – “Idaho, some of that difference is exported as final product”. Actually a lot more then “some”. According to my favorite source, the EIA, the 3.5 million bbls per day we export as refined products plus the 1.6 million bbls of crude oil we export = 49% of domestic production.

    Yes: about half the oil produced in the US is exported as raw crude and refined products. US oil production does not belong to its citizens. It belongs to private owners who are free to sell it to whomever they choose.

  15. rockman on Sat, 2nd Jun 2018 4:34 pm 

    Duncan – So you see the US consumers use 20 million (or 19.69) bbls per day minus 5.1 million bbls per day. Or 14.9 million(or 14.59 million) bbls per day.

  16. deadly on Sat, 2nd Jun 2018 8:52 pm 

    CALGARY _ The National Energy Board says Canadian oil exports rose by 6.5 per cent last year to 3.3 million barrels per day despite an increase in light shale oil production in the United States, Canada’s biggest customer and competitor.

    The federal regulator says heavy crude made up 77 per cent or 2.5 million bpd of Canadian exports, continuing a trend that has resulted in such exports rising by 48 per cent over the past five years as new oilsands projects come on stream in Alberta.

    Light oil exports fell six per cent in 2017 to 760,000 bpd, a reduction of 13 per cent from five years ago.

    The NEB says the U.S. still wants to buy Canadian heavy crude because many of its refineries are configured to process it and it is a cheaper feedstock than light oil.

    Higher oil prices and volumes resulted in the value of Canada’s oil exports rising to $66.9 billion in 2017 from $49.9 billion the year before.

    Last year, about 90 per cent of crude oil exports were moved by pipeline to the U.S., according to the NEB. Crude-by-rail export volumes rose 44 per cent due to pipeline capacity constraints, but remained a much less-utilized option at about 130,000 bpd.

    Canada Exports to US

    The reality is Canada provides 3.26 million barrels per day to the US.

    10.47 plus 3.26 is 13.73 million bpd with Canada’s contribution. The other six million comes from hither and yon.

    But wait, there is five million boepd to from shale gas.

    That makes only one more million from someplace like Saudi Arabia. Well, it is 760,000.

    Saudi exports to US

    Almost time to start drinking all over again.

  17. Anonymous on Sun, 3rd Jun 2018 7:32 am 

    Duncan, Davy already corrected this. We refine a bit over 18 M bopd, but only use about 14MM bpd of refined products (the excess is exported products). We basically need to reach about 14 MM bpd of crude production to be neutral on export/import of crude and products.

  18. Anonymous on Sun, 3rd Jun 2018 7:56 am 

    Rock (long post):

    Very well stated on the transport costs. WTI and Brent landed in Rotterdam trade at ten to fifty cents of each other. They are extremely similar (almost same gravity and sulfur) so this is unsurprising. The reasons for price difference on the metric are (ignoring storage) mostly the pipe from OK to the Gulf and then the shipping cost across the ocean.

    Looking at CME trading. (Free on the Internet, Google it). [JUL futures month, but closely approximates current trade in the physical barrel]:

    WTI (Cushing)-Brent: -$10.44 (that’s right…WTI is in the 65s while Brent is in the 76s!)

    WTI (Cushing)- WTI Houston: -8.21 [this is the pipe constraint WITHIN THE US]

    Therefore (calculated): WTI-Houston – Brent = -10.44 – (-8.21) = -3.26 [Yes, there is a difference, but not that extreme, seacoast to seacoast]

    One small thing that irks me is whenever people talk about WTI versus Brent driving imports. And they seem IGNORANT of the geography of the US and that OK has no sea coast! Really you need to talk about LLS versus Brent (or WTI-Houston versus Brent). The pipe between Cushing and the Gulf can get clogged at times (e.g. in 2013 before the Keystone South was opened).

    The interesting thing lately is that the basis difference is opening between Gulf Coast WTI (WTI-Houston OR LLS) and Brent. This is because the export facilities, already challenged by the lack of deep draft, are getting overwhelmed and causing a bottleneck. We just didn’t build this thing to send large amounts of oil seaward from the Gulf. Texans have ingenuity, but 2.5 MM bopd crude export starts to really strain the export infrastructure. This is actually a NEW phenomenon (during 2011-2014, the big WTI-Brent spreads were mostly from the Cushing pipe problem). You will always have some spread (costs $2-3 bucks to ship across the ocean, plus terminal/load/unload).

    But all that said…a bit over $3 is not that extreme when you are looking at the $10 overall basis difference. The main problem is pipe capacity south out of Cushing.

  19. Anonymous on Sun, 3rd Jun 2018 9:18 am 

    Rock: some small bones to pick with this:

    “Second, according to the EIA the majority of US oil exports are condensate/light oil (and not WTI)”

    1. First WTI is light oil (in my world).

    2. Second, the EIA does not have statistics of exports by crude gravity (as far as I know, but feel free to link if you know better).

    3. The studies I have seen (mostly pdfs of proprietary studies by Wood Mac or the like) show the major US export category IS WTI, either “Cushing blend” WTI or literally Midland crude.

    4. If your definition of “condensate” is 50 API, than certainly less than half of exports are below 50. This is because the US as a WHOLE produces less than 1 MM bopd at 50+. So it’s literally impossible for half of exports to be 50+.

    5. Even if your definition is 45+ for condensate (again not how most customers or marketers refer to it, but fine…the “cat piss” peak oil whiners can have one), it is still less than half of exports are over 45. The vast bulk of the exports are 40-45. There is also a modest but noticeable amount of exports of GOM Mars Field oil (medium gravity)…I have no clue why this happens, but it does.

  20. rockman on Sun, 3rd Jun 2018 2:45 pm 

    “The NEB says the U.S. still wants to buy Canadian heavy crude because many of its refineries are configured to process it and it is a cheaper feedstock than light oil.”. US refineries do not process heavy Canadian bitumen. Thus they don’t buy heavy Canadian bitumen. And the millions of bbls of Canadian oil we import daily is not heavy bitumen. It is “dilbit”…DILuted BITumin. A blend of bitumen and condensate/light oil. And the refineries don’t process that dilbit which is about 23 API. US refineries have for years refined oil with a very narrow range of gravity around 32 API.

    BTW last time I checked the stats Canada is importing around 330,000 bbls per day of condensate/light oil from the US to blend with the Alberta oil sands production to make the 23 API dilbit. IOW about 25% to 35% of the “oil” (really dilbit) we import from Canada is condensate/light oil. And once here it has to be blended further with more condensate/light oil to produce the 32 API oil our refineries are optimized to process.

    And for A: Here’s the definition of condensate according to Schlumberger: “A low-density, high-API gravity liquid hydrocarbon phase that generally occurs in association with natural gas. Its presence as a liquid phase depends on temperature and pressure conditions in the reservoir allowing condensation of liquid from vapor. The production of condensate reservoirs can be complicated because of the pressure sensitivity of some condensates: During production, there is a risk of the condensate changing from gas to liquid if the reservoir pressure drops below the dew point during production. Reservoir pressure can be maintained by fluid injection if gas production is preferable to liquid production. Gas produced in association with condensate is called wet gas. The API gravity of condensate is typically 50 degrees to 120 degrees.”

    Unfortunate according to the definition used by the Texas Rail Road Commission to characterize all Texas production (including the Eagle Ford Shale) it is not defined by the gravity of the produced liquid. The same 39 API liquid hydrocarbon from Well A may be posted as crude oil and the identical 39 API liquid hydrocarbon from Well B may be classified as condensate. The distinction is based on the phase of the liquid (either liquid or gaseous) as it exists in the reservoir. And to make matters even more confusing is that phase changes over time (has happens in a pressure depletion reservoir) those produced hydrocarbons can change classification from condensate to crude oil.

    This is not an insignificant bit of trivia. It has a statewide impact measured in $billions. It deals with the spacing requirements between wells. In general “gas/condensate wells” are required to be spaced much further apart (like one well every 640 acres) compared to “oil wells” spaced on 80 acre units (like 8 wells every 640 acres). So while a single gas/condensate well might hold 640 acre as long as the well is producing if production is reclassified as crude oil only 80 acres might be held. The leases on the other 560 acres (640 – 80) are lost unless the operator drills 7 new wells on those new 80 acre units.

    This is why you see Texas production numbers listed at “C+C”…crude + condensate. One cannot distinguish condensate from crude oil in Texas based on API gravity. Essentially it’s all oil. Since the Rockman produces oil/condensate in Texas he tends not to think of a gravity distinction. OTOH others do make the distinction at 50 API. But te Rockman has seen others use 40+ API as the definition of condensate. But notice even the Schlumberger definition says it’s “typically” 50+ API…not always 50+ API. If one wants to use 50+ API that’s OK. But they will have to research any number they quote from a source and confirm how that particular source defines the distinction. Obvious that can’t be done with stats put out by the TRRC.

  21. Harquebus on Sun, 3rd Jun 2018 6:21 pm 

    My understanding is that, some LTO is catagorized as oil but, is not sold on the oil market and therefore, is not crude oil even though it is counted as such.

  22. MASTERMIND on Sun, 3rd Jun 2018 7:08 pm 

    Pretty soon the EIA will be counting scotch whiskey and Bacardi 151..Into their “All Liquids” totals..Anything oily that burns..

  23. Anonymous on Sun, 3rd Jun 2018 9:12 pm 

    In Texas, it has legal implications (but still is somewhat arbitrary, not a physical thing, but a legal one…borderline wells may change over time to get the best tax treatment for instance). In the entire rest of the world it is just a matter of semantics. And for what it is worth, most refiners and middlemen (PAA, Flint Hill, PSX, etc.) define condensate at 50. But really it is sort of irrelevant. It is all “oil” in that it is a complex mix of hydrocarbons from C-1 to multi-ringed asphaltenes. The peakers seem to want to think of it as a molecular substance like natural gas or ethane or purity products like that. But it’s not. Difference between 49 and 50 is just a borderline. Same with difference form 44 to 45.

  24. Anonymous on Mon, 4th Jun 2018 1:28 am 

    US production (MM bopd)
    AUG17: 9.242
    MAR18: 10.474
    monthly increase: 0.176
    annualized increase: 2.112

    Note, I am biasing the analysis a little by picking the most extreme end points. Still, if you look at what has happened in the last 7 months, it was growth at a rate that would be over 2 million bopd/year. That is stunning. If it is maintained, it implies finishing the year at over 12 MM bopd.

    We are in uncharted territory. Record production. Hubbert’s 1970 peak eclipsed.

  25. Davy on Mon, 4th Jun 2018 4:28 am 

    Nony, I appreciate your input here. Not much contributions on this board anymore that are professional and on topic.

  26. Anonymous on Mon, 4th Jun 2018 7:25 am 

    Davy: No wuwwies, as my Aussie gf liked to say.

  27. Anonymous on Mon, 4th Jun 2018 7:30 am 

    Here is the percent US production by API gravity for the lower 48 (includes GOM, excludes Alaska)

    Category Mar-18 pct
    55.0 460 5%
    Unknown 30 0%
    Total 9,962 100%

    You can see that the percentage of production above 50 is less than a tenth. Even if you draw the line at 45 gravity, it’s less than a quarter of US production.

    The largest category is 40-45 API oil, at about a third of production. And don’t let anyone tell you that heavier oil is more valuable. It is not. Rockman goes to sell some oil and 40-45 is what gets the best price. See the daily crude bulletins put out by midstreamers and refineries who are actually buying the stuff.

    Note: Alaska is not shown since it does not well segregate oil by gravity. But it is about a half million bopd (5% of US total) and has an API gravity in the high 20s. So including it would just make US oil look heavier, not lighter.

  28. MASTERMIND on Mon, 4th Jun 2018 7:31 am 

    Anonymous

    Hubbert’s peak was made of purely conventional oil..Not junk oil like shale and natural gas and all sorts of other junk the EIA includes now..Not all energy is equal..

  29. Anonymous on Mon, 4th Jun 2018 7:31 am 

    Table was cut off. Let me try again:

    Category Mar-18 pct
    55.0 460 5%
    Unknown 30 0%
    Total 9,962 100%

  30. Anonymous on Mon, 4th Jun 2018 7:33 am 

    Maybe it is something from the indents.
    text.
    text.
    text.
    text.
    text.
    text.
    text.
    text.

    Category Mar-18 pct
    55.0 460 5%
    Unknown 30 0%
    Total 9,962 100%

  31. Anonymous on Mon, 4th Jun 2018 7:38 am 

    It is showing in preview, but not printing. Let me try doing it manually:

    Lower 48 oil by gravity:
    50: 9%

    You can see that the vast majority of US production is not ultralight.

  32. Anonymous on Mon, 4th Jun 2018 7:40 am 

    It’s still cutting off my post. I am at a loss. Let me try it in sentences. Less than 40 API oil is 44% of total. The 40-45 oil (classic, light sweet…highest priced, most valuable) is 33% of total. 45-50 is 13% of total. And higher than 50 is 9% of total.

  33. Anonymous on Mon, 4th Jun 2018 10:03 am 

    There seems to be a persistent misunderstanding of what hydrocarbons are.

    Natural gas is methane is CH4, is a purity product (single molecule gas).

    “Oil” is a complex soup of thousands of different molecules. It is a natural product. This is very different from what you are used to in chem lab with pure chemicals of single molecule liquids. It contains everything from straight chain hydrocarbons, to branching ones, to ringed ones. It even contains residual natural gas (this is normal, comes out in refining…happens because “like dissolves like”. Essentially hydrocarbons are non polar and like to dissolve in each other and avoid water. Like salad dressing.

    Crude versus lease condensate is basically an arbitrary distinction. Crude is the “oil” that comes from a well that mostly makes oil. Lease condensate is the “oil” that comes from a well that mostly makes gas. In TX, there are some small tax differences for this treatment. but many other states just call it all “oil” and never try to distinguish.

    When you have an oil well, what comes up it, typically consists of three phases of matter, one gaseous and two liquid. A device called a three phase separator is used at the site to make a first cut separation of these phases. It is basically a big knockout drum:

    The gas is on the top and is vented (to a pipe). This is mostly methane but will contain some other gases.

    Below the gas is liquid in two phases: ydrocarbons floating on top and water on the bottom). Just like in your salad dressing bottle. The water is taken out the bottom. The oil is taken out the middle.

    This is the first cut separation and gives you water, oil (crude and lease condensate) and “wet gas”.

    Water tends to be very salty and has some hydrocarbon residues and may have heavy metals or even radioactives (came from deep earth). It is typically reinjected deep underground. But it may be cleaned up and disposed. Or may be cleaned up for use in frack water.

    The oil is typically transported to refineries. Depending on the transport method and how volatile the oil is, it may need to be “stabilized”: essentially a very preliminary distillation (heating) that drives off some MORE natural gas and NGLs. This allows it to meet train or pipe vapor pressure specs if it didn’t already. The small amount of separated gas is considered a “product” and is not part of the wet gas number (the reported EIA oil number is before stabilization). But this is minor. Note, there is nothing sneaky about this…you will see there is secondary processing of gas that gives oil that doesn’t count back to oil either.

    Once the oil goes to a refinery it is processed in a complex set of steps but the most important is the first one, distillation. This is a huge, hundred foot plus tower with hundreds of “plates” or shelves that distill the fluid over and over to separate it based on boiling point (like making moonshine, but fancier). The basic cuts are light ends, naphtha, middle distillate, gasoil, and resid/bottoms.

    Light ends are C1-C4 (methane to butane). All substances that are gasses at room temp. C1 is methane (yes all oil still had some gas in it until the final squeeze…nothing sneaky here…been that way for all time…just how the chemistry works). The C1 is used in boilers in the refinery (and the refinery generally needs extra methane anyway…it is a net methane consumer, not producer). Ethane, C-2, is typically sent to a cracker (sold as a product) but may in some cases be used as fuel like C1. Propane, C-3, is a valuable product and is sold for space heating or chemical processing. Butane is mostly mixed into gasoline, especially in winter (in summer it is too hot for the vapor), but it may also be sold as a product for Bic lighters, chemical processing, etc.

    Naphtha is mostly C5-C8. It is the main component in gasoline but also goes into some chemical processes.

    Middle distillate is even longer chains and goes into diesel and jet fuel (kerosene).

    Gasoil is even heavier…it is typically cracked down in downstream processors that convert it into naptha, middle distillate, light ends, etc.

    Resids and bottoms: some resids are sold as very heavy and sulfurous fuel oil. (Not for home use…home fuel oil is basically diesel and is desulfurized.) Resid fuel oil typically goes into large ship boilers or power plants that are able to burn it. The market for this product is going away because of changes in the regulations for ship fuel oil (making it cleaner).

    The very heaviest grade (bottoms) are typically sent to a coker that cracks some of it to lighter streams (useful) and the rest of it into coke (essentially carbon…has a market but is very cheap).

    Back to the wet gas from the well head separator. That wet gas is the EIA number. However it is wet, mostly not with water but with larger hydrocarbons than methane. This gas is sent to an NGL plant that does a more complicated separation than is possible at the well site (refrigerates it to extreme cold temperatures to separate out the gases). This allows to separate out the ethane, propane and butane. These products are more valuable than methane so better to send them to markets. Also, if left in the gas stream, it would burn too hot and damage appliances…would violate commercial specs. Sometimes, some ethane is left in the gas stream since ethane is in a glut…but still the amount is limited by pipeline specs.

    In addition to the gaseous NGLs, a small amount of liquid hydrocarbon is extracted as well at the refrigeration site. This is called plant condensate but is much lighter than lease condensate (70 API versus 50 API). It is mostly pentane, C-5, but contains some higher hydrocarbons. This is a liquid hydrocarbon but it is NOT part of the EIA oil number. So here is an example where you could say the oil number was low. Plant condensate is pretty similar to the refinery distillation cut called naphtha and goes into similar uses (gasoline blending, chemical processing, diluent for bitumen).

    Finally very small amounts of non hydrocarbon gases are separated (water vapor, nitrogen, carbon dioxide, hydrogen sulfide). These are essentially worthless and are disposed of.

    The final pure methane is called “dry” natural gas. You will always have a smaller dry gas number than wet gas number, mostly from removal of the more valuable NGLs. Note that the NGLs are NOT part of the EIA oil (crude and condensate) number. No. No. No. Just no. NGLs are a part of the “wet gas”.

  34. Anonymous on Tue, 5th Jun 2018 12:03 am 

    Rock: see chart on export types (second tweet):

    https://twitter.com/T_Mason_H/status/1003740734384738312

    The grey is unknown type. Of the known types, it varies by month, but looks like about 70% is WTI, about 20% is Eagle Ford (probably Eagle Ford 47, but maybe some condensate too) and then 10% is Gulf of Mexico. Only the Eagle Ford is super light.

    I would even doubt that it is much condensate. Because it turns out there are a lot of condensate splitters with excess capacity on the Gulf Coast. (built during the boom and before the export ban change). It’s really classic WTI that is in excess, not condensate.

  35. GregT on Tue, 5th Jun 2018 12:59 am 

    Nony,

    See chart on how fucked up your future is going to be for continuing to cheerlead fossil fuels:

    https://climate.nasa.gov/vital-signs/carbon-dioxide/

    You have nobody to blame but your greedy self.

  36. Anonymous on Tue, 5th Jun 2018 4:40 am 

    Whether you want FF to be burned is a different topic than estimating peak oil. Ideally, you should have an objective estimate of the resource development regardless of what outcome you prefer to happen, regardless of politics.

  37. MASTERMIND on Tue, 5th Jun 2018 5:15 am 

    Almost half of US families can’t afford basics like rent and food

    http://money.cnn.com/2018/05/17/news/economy/us-middle-class-basics-study/index.html

  38. DerHundistlos on Tue, 5th Jun 2018 5:31 am 

    Nony-

    U are totally busted. Thanks, Greg, for outing the turd-blossom.

  39. Davy on Tue, 5th Jun 2018 5:47 am 

    “Whether you want FF to be burned is a different topic than estimating peak oil. Ideally, you should have an objective estimate of the resource development regardless of what outcome you prefer to happen, regardless of politics.”

    Exactly Nony, well said.

  40. fmr-paultard on Tue, 5th Jun 2018 6:23 am 

    why is the cattle multilator still here attacking supertard? still photographic proof of aliens/UFO probing. oh but “FBI investigated!”

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