Geologic Time, Oil Formation and Secretary Chu

Last week ,as Climate Audit caught, the Seretary of Energy was asked about how oil and gas got into the Arctic Rocks. Now there is a little catch to the question, in that for oil to be formed the local environment has to be quite warm particularly relative to today’s Arctic temperatures (as explained below). Thus, to explain how the oil got there, the Secretary would have to admit that there was a period when the Arctic was warmer than today. However Dr Chu did not want to give that answer, and so he proclaimed that the rock and oil-forming algae were deposited elsewhere and then migrated, under Continental Drift, until they ended up in the Arctic. Steve gave a condensed answer pointing out how wrong the Secretary is on this, but I thought I would use the error as a base for explaining the origins of oil and natural gas in a post that I can then relate to later.

The majority of world opinion on the matter, has concluded that oil and natural gas originated in the bodies of small organisms, such as modern algae, which can include up to around 56% lipid material (their version of fat). This is referred to occasionally as the biotic source, as opposed to an alternate theory, the “abiotic” theory. This latter theory, which came out of Russia and gained some acceptance in the West, in essence says that oil is generated deep underground by chemical reactions, similar to the Fischer-Tropsch process used to make synthetic oil. While the relevance of this process to oil supply has been disputed, it relies in part on the idea that there are deep pools of oil that fill old reservoirs back up after they are depleted and that if we just drilled deep enough to find them we would have an almost inexhaustible supply. And the catch with that relates to the formation of oil and gas through the biotic explanation.


The biotic explanation for oil and gas formation proposes several steps along the way. First we have the rivers and shallow seas where the algae flourished and died. Sinking to the bottom they mixed with the sediment that is also deposited in such places (and which can be seen in parts of the world today). With time, as with the formation of coal, the sedimentary beds that hold the nascent hydrocarbon fuels are buried deeper. With an increasing depth of burial comes an increase in pressure and temperature. As a very rough rule I use 1 psi of pressure for each foot of burial, and 1 degreeF for every 60 ft of depth startin at 60 deg at 60 ft. So that, for example, at a depth of 3,000 ft the ground pressure is 3,000 psi and the temperature will be 110 deg F.

An early step along the way, as our hydrocarbon starts to cook is its transformation to a kerogen. This is the “oil” of the oil shales of Colorado, New Mexico and Utah. It is not yet a liquid and does not flow. To get to that stage it has to be buried deeper and heated longer. That is what Shell is planning to emulate with their process for oil recovery from the shale. By inserting long heaters into holes down through the rock, and raising the temperature to 650 – 700 deg F and holding at that temperature for 2-3 years they hope to complete the transformation. The temperature is higher than that which would be needed for the natural process, because the process must happen faster. With nature and depending on the part of the world you are in (since the geothermal gradient varies) the transition will occur when beds lie in the 3,000 ft to 15,000 depth.) (Temperatures up to 300 deg F range. ) This depth range is often referred to as the oil window, since shallower rocks aren’t cooked well enough and we get kerogen, and if the rock goes deeper then the higher temperatures will “crack” the oil into natural gas.

(Which is where the problem of deeper pools of oil for abiotic oil comes up, since the deeper pools that the theory calls for would exist at depths where the oil would be cooked into gas, and thus no longer available to supply the oil).

As the oil heats it also thins and becomes less sticky so that it can start to slide through the grains of the surrounding rock, passing along small cracks and being pushed up, in part by the water that was trapped in the rock with it, and which starts to collect below the oil. The oil will move up through the layers of rock until it either reaches the surface, or it is trapped below a rock which does not have the passageways (permeability) wide enough for the oil and water to pass through.

Similarly the deeper deposits that have turned into gas will also begin to move up until they too are trapped beneath an impermeable cover or cap rock.

OK, so when did this happen? Well it depends on the place you’re at. But, for example if we go up to the North Slope of Alaska, the rocks that generated the oil are known as source rocks, and the USGS has identified rocks of the Triassic (the Shublick) ; the Jurassic (Kingak) and the Cretaceous periods may all have contributed oil.

Source USGS

Now a quick peek at a geologic column tells us that these are periods of the Mezozoic Era which ran from the end of the Cretaceous ( 65 million years ago) through the Jurassic (ending 165 million years ago) to the Triassic which ended 208 million years ago. They are younger than the Carboniferous, when coal beds were laid down, by some 40 million years or more.

However, to get back to Dr Chu’s point about Continental Drift having carried the oil bearing rocks up to Alaska, after they were formed, if you go to any of the models which show how the plates have moved, the North American plate (which includes Alaska) was already up in place as far as the North is concerned (but then drifted West) by the beginning of the Jurassic.

So while this was a good try by Dr Chu, a Climate Warming devotee, to get around some geological truths, the facts argue against him. (Not to mention more recent findings within the Holocene, our current geological Era), but we'll save those for another day.
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SEC Rules Changes for Oil & Gas Reserves

Yesterday I was talking about the calculation of reserves for coal mines, and the calculation of what a reserve holds is a critical part of raising the capital to put a mine in place. The same holds true about oil and gas wells, as their price rises above $5 million a well, and at the end of last year the SEC changed the rules on Oil and Gas Reserve Reporting. It is interesting to read the rationale for the changes. Part of the problem has been that the industry has been developing technologies that make it easier to economically extract oil from tar sands, and also to get natural gas from coal seams and from shales that had previously been uneconomical to develop. However, where the rules that define reserves do not allow a full accounting of the volumes that can be recovered, then it becomes harder to raise capital for the operation. The rules were last written in the time that most extraction came from the historic vertical wells that drilled down into a deposit and extracted the gas. With both coal and shale extraction the new technologies have advanced considerably beyond this, and to make the situation more realistic the rules had to be changed.

In the extraction of gas from shale beds, for example, the rock is normally made up of very fine grains, which provide very poor permeability (or passageways) for the gas to work through the rock to get to any well that is there. Rates of flow to the well would thus be too slow to be economic. To enhance the flow operators therefore drill long horizontal holes along the layer of rock holding the gas. Pressure in the well is then raised, until cracks are created in the wall of the well, and with more pressure these are extended out into the rock providing a path for the gas to flow back to the well. While this technique (of which more some future Sunday) creates passages through the rock that allow the gas to flow to the well in larger volumes, and makes the well potentially economically viable it has put artificial connections into the rock. Part of the old definition of reserves was that the oil/gas already had the connections in place in the rock to ensure that the fluid could flow to the well if it was drilled. Further the presence of oil had to be proved by drilling a well into the rock and actually showing that it was there. Thus the term “proved oil and gas reserves.”

To recognize that there are more sophisticated tools that can now tell much more about the presence of oil/gas in a rock without needing to drill that proving well, the SEC have changed the rules to read:

The proposed revisions to the definition of “proved oil and gas reserves” also included provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations. We are adopting those revisions as proposed.

We also are adopting, as proposed, revisions that permit a company to claim proved reserves beyond those development spacing areas that are immediately adjacent to developed spacing areas if the company can establish with reasonable certainty that these reserves are economically producible. These revisions are designed to permit the use of alternative technologies to establish proved reserves in lieu of requiring companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells.

Of course having written such a statement, one has to clarify what is meant by “high degree of certainty” (since there is no longer the physical evidence of oil on the end of the “dipstick”). This they have done by definition:

Therefore, we are adopting the “high degree of confidence” standard that exists in the PRMS. We also are clarifying that having a “high degree of confidence” means that a quantity is “much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease” to provide elaboration to the definition of reasonable certainty.

The other change that I want to highlight comes in the estimation, knowing that an existing site has oil/gas, as to how far out from that point the field can be considered to extend, and this is known as the “undeveloped reserve.” Here the decision is based on the degree of certainty that the field actually extends into that space. And the language has been loosened to make it easier to include those more distant reserves.

In the Proposing Release, we proposed a significantly revised definition of the term “proved undeveloped oil and gas reserves.”

The most significant aspect of the proposed revision was the replacement of the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test. Currently, the definition of the term “proved undeveloped reserves” imposes a “reasonable certainty” standard for reserves in drilling units immediately adjacent to the drilling unit containing a producing well and a “certainty” standard for reserves in drilling units beyond the immediately adjacent drilling units.104 All commenters on this issue supported the proposal. Three commenters noted that a single standard—reasonable certainty—should apply to all proved reserves. We are adopting this aspect of the definition as proposed.

Since the companies no longer have to actually drill into a formation and prove the oil is there the old fashioned way, the big question transfers to the reliability of the technologies that are used to determine that oil is actually present. And here, since technologies continue to change, the words have been generalized

We also proposed to define the term “reliable technology,” expressed in probabilistic terms, as technology that has been proven empirically to lead to correct conclusions in 90% or more of its applications. Several commenters expressed concern that this proposed 90% threshold would be difficult to verify and support on an ongoing basis. We agree that a bright line test would be difficult to apply to a particular technology or mix of technologies to determine their reliability. Therefore, we are not adopting the 90% threshold as part of the definition.

And while changing the rules to include production from tar sands can be readily easily accomplished:

Our current definition of “oil and gas producing activities” explicitly excludes sources of oil and gas from “non-traditional” or “unconventional” sources, that is, sources that involve extraction by means other than “traditional” oil and gas wells. These other sources include bitumen extracted from oil sands, as well as oil and gas extracted from coal and shales, even though some of these resources are sometimes extracted through wells, as opposed to mining and surface processing. However, such sources are increasingly providing energy resources to the world due in part to advancements in extraction and processing technology. Therefore, the rules we adopt today revise the definition of “oil and gas producing activities” to include such activities.

However it does require a definition of bitumen, which they provide

We are defining the term “bitumen” as “petroleum in a solid or semi-solid state in natural deposits. In its natural state, it usually contains sulfur, metals, and other non- hydrocarbons. Bitumen has a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.”

And to address the point that I began with about accumulations of gas in unconventional places the regulations will change:

Although we agree conceptually that the focus of reserves disclosure should be on the final product, we also recognize that the production of oil and gas from varying sources can have significantly different economics. Extraction of oil and gas from continuous accumulations can be much more labor and resource intensive than extraction of oil and gas from traditional wells. They often require greater ongoing efforts and expense after the initial extraction equipment is in place, making such operations more sensitive to price fluctuations.

We agree with the commenters that disclosure based on the end product sold would provide a more effective basis for distinguishing reserves that disclosure based on the type of accumulation in which the reserves are held. Therefore, we have revised the disclosure to be based on the end product that is sold by the company However, with respect to the end product, new Item 1202 makes a distinction between oil and gas, on the one hand, and synthetic oil and gas, on the other. Synthetic products require processing of the raw resource material, either while it is still in the ground (“in situ”) or after it is extracted, before it can be used as refinery feedstock or as natural gas. Such processes currently include bitumen upgrading as well as coal liquefaction and gasification. However, resources from some continuous accumulations, such as coalbed methane, do not require such processing and therefore are not associated with the same level of ongoing costs once a well has been drilled because the in-ground resource is already oil or gas (in the case of coalbed methane, the in-ground resource is methane, trapped in a coalbed). Thus, coalbed methane would not be considered a synthetic product.

I think it is a fair comment to note that these relaxations of the rules will allow companies to claim significantly larger reserves, than heretofore allowed, although it should be born in mind that it actually won’t change the actual volumes of oil and gas in the ground by one molecule.

How do we make up for Mexico's declining exports?

The current turmoil over the supply of gas from Russia, highlights the increasing dependence that the world has to place on energy supplies from a shrinking pool of suppliers. This past week the Energy Information Agency (EIA) shows that the United States imported some 14.5 million barrels of oil a day (mbd). Domestically we produced 4.9 mbd, having fallen below 5 mbd just as the calendar kicked over into December, 2008. The October import figures the most recent available, (pdf) show 6 mbd came from OPEC countries and 7.4 mbd from non-OPEC nations.

This supply came from a total of 49 countries, ten of whom are in OPEC and 39 of whom aren’t. However if we count only countries that contributed more than 250,000 bd to this supply we end up with Canada (2,567 kbd); Saudi Arabia (1,487 kbd); Mexico (1,483 kbd); Venezuela (1,162 kbd); Nigeria (979 kbd); Iraq (577 kbd); Algeria (555 kbd); Angola (539 kbd); Russia (394 kbd); Brazil (354 kbd); the United Kingdom (386 kbd): and the U.S. Virgin Islands (267 kbd).

One of the reasons for putting the list up here and now is that we can come back, next year and see how things have changed, and note how and where the dependence has moved to. But, as I noted in Pick Points, Mexican production has fallen to around 3 mbd, of which half is exported to the U.S., and if their production continues to fall at 500,000 bd per year, then within this next year there is going to be some greater crunch between domestic use and exports. So where will the United States make up the difference?


Now the volume each supplies varies by month, two months ago Norway supplied (for that month) 2.175 mbd so that drawing conclusions from a single month is of no great value, but if one goes back and looks at figures for 2007 (pdf), one ends up with almost the same list, only Brazil having since joined (by 154 kbd). In 2005 the top 14 countries importing to the US would have dropped off Russia, Brazil and the U.S. Virgin Islands, but Colombia, Ecuador, Kuwait and Equatorial Guinea were still on it.

The largest proportion of the U.S. imports come from Canada, yet outside of the Oil Sands of Alberta and the possibilities of production from the Bakken shale, their production has been declining, with the Newfoundland fields perhaps peaking at 369 kbd in 2007. The oil sand production, currently at 1.4 mbd is scheduled to increase, with an initial target of 3.5 mbd, once planned for 2015, but now slipped back to 2020. Unfortunately for US consumers, there are two snags to relying on this source to offset Mexican declines. The first is the slowing of the expansion plans of those working the oil sands as prices fall; the second is:

The 2007 federal energy bill says U.S. government fleets can't buy fuel from the oil sands and other sources whose production emits more greenhouse gases than conventional oil.

And if someone gets serious about enforcing that . . . . .
So if Canada cannot expand their production enough, and Mexico is going to cut their exports, for the sake of discussion by 0.5 mbd, where do we look to next?

That would be Saudi Arabia, from which we get about 1.5 mbd. But Saudi Arabia is a strong advocate of OPEC production cuts and has already dropped their production from a peak of 9.7 mbd to 8.5 mbd in November. While it may go lower, probably not below 8 mbd, they have just warned Asian customers that cuts, of up to 15% will continue. So no luck there.

Moving down the list of suppliers, in terms of import size, that takes us to Venezuela. This is an interesting case, since there is a fairly large difference between how much oil the country says it is producing (3 mbd) and the amount others have estimated (2.4 mbd). In accord with OPEC wishes to cut production, so that prices will move back up, Venezuela is cutting some 189 kbd or production, 166 kbd of which was going to the United States. So I guess we’d better not look there.

Next on the list, moving down, is Nigeria, where we get just under 1 mbd. Well they are currently exporting, in total, around 1.66 mbd, but this is a cut of 12% (from 1.88 mbd) to accord with OPEC requests.. Although the country has a potential to produce perhaps 2.5 mbd, the problems that have been created by widespread conflict has pulled it down to perhaps the current level, although, with perhaps as much as 200,000 being siphoned off to illicit sales, it is going to be difficult to estimate true production – but I wouldn’t gamble on getting more out either.

And so we come to Iraq, which has now, with 0.577 mbd, made it to sixth on the list. A year ago I would have thought that increasing that number would have been almost impossible, but the nation is moving ahead with plans to double oil production (from around 2.5 mbd today, of which 1.85 mbd is exported), within three or four years. If this can be achieved, and one of the fields planned for expansion lies beneath Baghdad, then this could solve the US shortage , if not . .

The next candidate on the list is Algeria. But while their production is continuing to rise, together with exports, they also hosted the latest OPEC meeting with its call for 3.3 mbd of oil cuts. Thus while the US may get up to about a third of their exports, of about 2 mbd total production, their share is not going to go up in the short term, even though they hope, when markets grow, to increase production to 2.6 mbd by 2018..

Angola is eighth, but as a member of OPEC they are falling in line to drop production, from the 1.9 mbd that they produced in 2008, even though new fields are coming into production, and the production cut is anticipated to lower this to 1.5 mbd.

At ninth in line, there is Russia. But while Russia now vies with Saudi Arabia to be the worlds largest producer of oil, it has announced that it will go along with the OPEC cuts and, in collaboration with Azerbaijan, reduce their output by 600,000 bd. There is also a question as to whether overall Russian production has not peaked, since production last year fell year-on-year (Y-o-Y) by 815 kbd, to 9.74 mbd, with exports falling 16% to 3.53 mbd. Guess we had better not look there.

And so we come to the tenth candidate – which is Brazil. Brazil reached energy in 2006, but though a lot of credit was given to sugar cane ethanol the reality is that it was achieved with increased production of oil, particularly from offshore. However the costs for developing those fields is above the current price of selling the oil from those fields. So maybe we should not send out tankers down there yet.

Hmm, well lets see where that leaves us, Can it be that we are left hoping for production increases from Iraq as our likely savior, should demand start to resurrect?


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