“North American energy independence by 2020″

GOP presidential candidate Mitt Romney recently released an outline of his plan to achieve “North American energy independence” by 2020.    While the white paper (1) is short on specific details, it does contain quite a few good ideas and some supporting documentation.   For anyone interested in a business plan approach to energy policy, it’s well worth reading.  Rather than focus on the details of the plan, I thought it would be an interesting exercise to see if “North American energy independence by 2020″ was even technically possible.  If it’s not technically possible, then it’s not really relevant whether or not it would be economically advisable or politically achievable.   Since North America is already pretty well has the capacity to be energy independent in terms of coal, natural gas, uranium and electricity generation, I’m only going to look at oil and natural gas liquids.

So, without any further prologue, I’m going to jump right into some numbers. 

Can we “get there from here”?

According to the American Petroleum Institute (2) the current estimate of undiscovered technically recoverable Federal resources (UTRR-Fed) of crude oil currently stands at 116.3 billion barrels.  

Figure 1. U.S. Crude Oil and Natural Gas Undiscovered Technically Recoverable Federal Resources (American Petroleum Institute).

The UTRR-Fed are concentrated in areas close to existing exploration and exploitation infrastructure.  The Gulf of Mexico, Alaska and the Lower 48 States comprise 88% of the UTRR-Fed.

Region Offshore/Onshore Billions of Barrels of Crude Oil % Cum. %
Gulf of Mexico Offshore 44.9 39% 39%
Alaska Offshore 26.6 23% 61%
Alaska Onshore 18.8 16% 78%
Lower 48 Onshore 11.7 10% 88%
Pacific Offshore 10.5 9% 97%
Atlantic Offshore 3.8 3% 100%
Total   116.3 100%  

There is no reason that these potential resources could not be exploited within the next few decades if the U.S. government adopted regulatory policies geared toward exploitation. 

If industry converted the UTRR-Fed into proved developed producing reserves of crude oil over the next 25 years, this is what might happen to U.S. domestic crude oil production:

Figure 2. Potential exploitation scenario for the UTRR-Fed.

I think that it is technically possible that US crude oil and natural gas liquid production could reach 14.4 million BOPD by 2028 and peak at 15.7 million BOPD by 2032. If U.S. demand remained in the 18-20 million BOPD range, the United States could come very close to being self-sufficient in crude oil. I also took the liberty of including 73 billion barrels of Green River Oil Shale production from 2022-2100 (more on this later).

Canada expects to double its oil production by 2030 (3).  Assuming that Canada’s domestic consumption remains stable and the U.S. remains Canada’s primary export market, Canadian imports could also be expected to double by 2030.  While Mexican oil production is currently in decline and Pemex is one of the most poorly managed national oil companies (NOC) in the world, Mexico has huge potential in the area of undiscovered resources (4).  Mexico does have the potential to stabilize its current production levels.  If Canada doubles its production by 2030 and continues to increase its production through the end of this century and Mexico stabilizes at roughly its current levels, this is what U.S. domestic production plus Canadian and Mexican imports might look like:

Figure 3. U.S. UTRR-Fed plus Canadian and Mexican imports.

Based on these numbers, North American energy independence could be achieved by 2027.

116 billion barrels of ”undiscovered technically recoverable oil” is equal to about 16 years worth of current US consumption. However, past history shows us that gov’t agencies always grossly underestimate what the oil industry will find and produce. Alaska’s North Slope has already produced 16 billion barrels of petroleum liquids. Currently developed areas will ultimately produce a total of about 30 billion barrels. The government’s original forecast for the North Slope’s total production was 10 billion barrels. The current USGS estimate for undiscovered oil in the Bakken play of Montana & North Dakota is 25 times larger than the same agency’s 1995 estimate. In 1987, the MMS undiscovered resource estimate for the Gulf of Mexico was 9 billion barrels. Today it is 45 billion barrels (2).

The MMS increased the estimate of undiscovered oil in the Gulf of Mexico from 9 billion barrels in 1987 to the current 45 billion barrels because we discovered a helluva a lot more than 9 billion barrels in the Gulf over the last 20 years. Almost all of the large US fields discovered since 1988 were discovered in the deepwater of the Gulf of Mexico. In 1988, it was unclear whether or not the deepwater plays would prove to be economic.The largest field in the Gulf of Mexico, Shell’s Mars Field, was discovered in 1989. Prior to this discovery, no one thought that economically viable Miocene-aged or older reservoirs existed in deepwater. Mars has produced 1 billion barrels of oil and 1.25 TCF of natural gas since coming on line in 1996. It is currently producing over 100,000 barrels of oil per day. Dozens of Mars-class fields have been discovered over the last 20 years… Most of those have only barely come on line over the last 5 years.

The most significant play in the Gulf of Mexico, the Lower Tertiary, wasn’t even a figment of anyone’s imagination in 1988. These are massive discoveries – BP’s recently discovered Tiber Field on Keathly Canyon Block 102 is estimated to contain 3-6 billion barrels of recoverable oil. Several recently discovered fields are expected to come on line at more than 100,000 bbl/day. This play is still in its infancy.

Based on the gov’t’s track record, the estimated 116 billion barrels of undiscovered oil under Federal lands is more likely to be 680 billion barrels. That’s close to 100 years worth of current US consumption – And that’s just the undiscovered oil under Federal mineral leases.

When you factor in shale oil (kerogen) plays, the numbers become staggering.   The Green River formation oil shale has more than 1 trillion barrels of recoverable oil just in the Piceance Basin of Colorado.

  • There are at least 1.8 trillion barrels of undiscovered technically recoverable oil in just the Green River formation (DOE).
  • Oil shale deposits like the Green River formation (technically a marl) are currently economic at sustained oil prices of $54/bbl, possibly as low as $35/bbl (DOE).

In my hypothetical production forecast, I projected Green River oil shale production to reach 15 million BOPD by 2096.  Am I being overly optimistic in projecting more than 15 million barrels per day (BOPD) of production from oil shales by 2100?  Shell estimates that they could be producing 500,000 barrels per day from the Picenance Basin with a very small footprint using an in situ recovery process (5):

Technical Viability and Commercial Readiness (pp 18-24)

Shell has tested its in-situ process at a very small scale on Shell’s private holdings in the Piceance Basin. The energy yield of the extracted liquid and gas is equal to that predicted by the standardized assay test.13 The heating energy required for this process equals about one-sixth the energy value of the extracted product. These tests have indicated that the process may be technically and economically viable.

This approach requires no subsurface mining and thus may be capable of achieving high resource recovery in the deepest and thickest portions of the U.S. oil shale resource. Most important, the Shell in-situ process can be implemented without the massive disturbance to land that would be caused by the only other method capable of high energy/resource recovery—namely, deep surface mining combined with surface retorting. The footprint of this approach is exceptionally small. When applied to the thickest oil shale deposits of the Piceance Basin, drilling in about 150 acres per year could support sustained production of a half-million barrels of oil per day and 500 billion cubic feet per year of natural gas.

[…]

Once oil shale development reaches the production growth stage, how fast and how large the industry grows will depend on the economic competitiveness of shale derived oil with other liquid fuels and on how the issues raised in Chapter Five are ultimately resolved. If long lead-time activities are started in the prior stage, the first follow-on commercial operations could begin production within four years. Counting from the start of the production growth stage and assuming that 200,000 barrels per day of increased production capacity can be added each year, total production would reach 1 million barrels per day in seven years, 2 million barrels per day in 12 years, and 3 million barrels in 17 years.

Assuming a 12-yr lead time to reach the production growth stage, it will take ~30 years to reach 3 million barrels per day. If production continued to grow at a rate of 1 million BOPD every 5 years… Oil shale production from just the Piceance Basin could reach 15 million BOPD by the end of this century.

The hydrocarbon characteristics of the the oil shales of the Green River formation in the Piceance Basin are superior to those of the Athabasca oil sands. The hydrocarbon areal density is about 13 times that of the Athabasca deposits. The Green River hydrocarbons are not technically “oil;” it’s a form of kerogen. But, for or refining purposes, it’s oil. It will be booked as oil, just like the Athabasca tar sand oil is. It’s a high-grade refinery feedstock…

“Kerogen can be converted to superior quality jet fuel, #2 diesel, and other high value by-products.”

Canada is currently producing ~ 1 million barrels of oil per day from Athabasca oil sand deposits. They expect to increase that to 2 million barrels per day over the next decade. The Green River oil shale deposits in the Piceance basin could easily outperform Athabasca within a decade and with a much smaller environmental footprint.

Athabasca oil sands are currently economically competitive with the OPEC basket. Green River formation oil shales are superior, by a wide margin, to Athabasca oil sands. The Green River oil shales would yield 100,000 bbl of 38° API sweet refinery feed per 160,000 tons of ore & overburden. Athabasca oil sands yield 100,000 bbl of 34° sweet refinery feed per 430,000 tons of ore & overburden. The unconventional oil is actually very light and very sweet; the OPEC Basket is actually heavier (32.7° API).

Athabasca is economically competitive now. Green River could be economically competitive now.  The only obstacles to US energy security are environmental terrorists activists and the U.S. government.

“Peak Oil,” if it exists, won’t be reached for hundreds of years if the U.S. government would just get out of the way.  About 80% of the most prospective Green River deposits are under Federal leases.  The Obama administration effectively blocked exploitation of the Green River oil shale earlier this year.

Does Policy Matter?

Bad policy certainly matters.  “One bipartisan policy tradition is to deny Americans the use of our own resources” (6):

Figure 4. Bad Policy Matters.

The Obama administration’s energy policy has been disastrous as it relates to oil production.  While it is true that U.S. domestic oil production has been rising over the last few years, all of the growth has come from onshore plays in Texas and North Dakota:

Figure 5. Comparison of daily oil production rates: Federal Gulf of Mexico, Texas and North Dakota (EIA).

Some of the Texas (less than 1%) and North Dakota (~11%) production is from Federal leases.  I downloaded the onshore Federal lease production data for Texas and North Dakota from Office of Natural Resource Revenue (ONRR) and subtracted the minuscule Federal lease production from the State and private lease production in those two States. I added that to theFederal Gulf of Mexico production (the GOM is the Big Kahuna of Federal lease oil production):

Figure 6. State and private lease production in Texas and North Dakota vs. Federal lease production in the Gulf of Mexico, North Dakota and Texas.

All of the net growth in US domestic oil production since 2009 has come from State and private leases in Texas and North Dakota.

Since President Obama took office, Federal lease oil production in the GOM, TX and ND has declined by 79 million barrels per year; while State and private lease production in TX & ND has grown by 205 million barrels per year.  The decline in Gulf of Mexico has occurred during a period of high oil prices and is directly attributable to the unlawful drilling moratorium and “permitorium” imposed in the wake of the Macondo blowout and oil spill.  Drilling permits that once took 30 days to be approved now take more than 300 days.  Even relatively simple things like the approval of development plan (DOCD) revisions are being drawn out to nearly 300 days.  The average delays for independent oil companies are currently 1.4 years on the shelf and almost 2 years in deepwater (7):

Figure 7. Average Gulf of Mexico permit delays (Quest Offsore Resources).

Between the “permitorium” and high product prices, many of the best, most capable drilling rigs have been moved overseas.  Once we manage to get permits approved, the delays in obtaining a rig can be almost as long as the permit delays were.  In this “dynamic regulatory environment,” wells can’t be drilled quickly enough to compensate for decline rates, much less to increase production.

References:

(1) Romney for President, Inc. 2012. “The Romney Plan for a Stronger Middle Class: Energy Independence.”

(2) American Petroleum Institute. 2012. “Energizing America: Facts for Addressing Energy Policy.”

(3) CBC News. 2012. Canadian oil production to double by 2030, industry predicts.

(4) Talwani, Manik. 2011. “Oil and Gas in Mexico: Geology, Production Rates and Reserves.” James Baker III Institute for Public Policy.

(5) Bartis, James T. 2005. “Oil shale development in the United States : prospects and policy issues.” RAND Corporation.

(6)  Ford, Harold.  2011.  “Washington vs. Energy Security.”  The Wall Street Journal.

(7) Quest Offshore.  2o11. “The State of the Offshore U.S. Oil and Gas Industry.”

EIA. US Crude Oil & Petroleum Liquids Consumption

EIA. US Natural Gas Plant Liquids Production

EIA. US Crude Oil and Natural Gas Condensate Production

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9 Responses to ““North American energy independence by 2020″”

  1. David Middleton Says:

    The “it’s not going anywhere” strategy will turn “35 to 36 billion barrels of oil and 137 trillion cubic feet of natural gas” into “9 to 10 billion barrels of oil” and no gas and lead to the North Slope being shut in by 2025, stranding “about 1 billion barrels of oil.”

    The Trans Alaska Pipeline System’s (TAPS) minimum flow rate of about 300,000 barrels of oil per day will be reached in 2025, absent new developments or reserves growth beyond the forecasted technically remaining reserves. An Alaska gas pipeline and gas sales from the Point Thomson field and the associated oil and condensate would provide another boost to oil production and extend the life of TAPS for about one year to 2026. A shut down of TAPS would potentially strand about 1 billion barrels of oil reserves from the fields analyzed.

    Page ix

    For the complete study interval from 2005 to 2050, the forecasts of economically recoverable oil and gas additions, including reserves growth in known fields, is 35 to 36 billion barrels of oil and 137 trillion cubic feet of gas. These optimistic estimates assume continued high oil and gas prices, stable fiscal policies, and all areas open for exploration and development. For this optimistic scenario, the productive life of the Alaska North Slope would be extended well beyond 2050 and could potentially result in the need to refurbish TAPS and add capacity to the gas pipeline.

    The forecasts become increasingly pessimistic if the assumptions are not met as illustrated by the following scenarios.

    1. If the ANWR 1002 area is removed from consideration, the estimated economically recoverable oil is 29 to 30 billion barrels of oil and 135 trillion cubic feet of gas.

    2. Removal of ANWR 1002 and the Chukchi Sea OCS results in a further reduction to 19 to 20 billion barrels of oil and 85 trillion cubic feet of gas.

    3. Removal of ANWR 1002, Chukchi Sea OCS, and the Beaufort Sea OCS results in a reduction to 15 to 16 billion barrels of oil and 65 trillion cubic feet of gas.

    4. Scenario 3 and no gas pipeline reduces the estimate to 9 to 10 billion barrels of oil (any gas discovered will likely remain stranded).

    Some combination of these hypothetical scenarios is more likely to occur than the optimistic estimates.

    Page viii

    “Drill baby, drill” will extend “the productive life of the Alaska North Slope… well beyond 2050″ and recover 25 to 27 billion barrels of oil and 137 trillion cubic feet of gas that would otherwise have to be imported.

  2. David Middleton Says:

    @oneman50,

    No. I did not factor in the increased use of CO2 for secondary recovery. One Dallas area independent oil company,Denbury Resources, is probably the industry leader in this area.

    Here are a couple of good papers on the subject:
    Improving Domestic Energy Security and Lowering CO2 Emissions with “Next Generation” CO2-Enhanced Oil Recovery (CO2-EOR)
    BASIN ORIENTED STRATEGIES FOR CO2 ENHANCED OIL RECOVERY: OFFSHORE LOUISIANA

  3. David Middleton Says:

    James F. Evans says:
    September 2, 2012 at 1:16 pm
    David Middleton wrote the following were not evidence of abiotic oil:
    “The Dnieper-Donets basin.
    The fractured granite reservoirs of the Cuu Long basin.
    Eugene Island Block 330 oil field.
    The ultra-deepwater Lower Tertiary play in the Gulf of Mexico.
    The deep subsalt plays offshore Brazil.
    Lost City.
    The Saturnian moon Titan”

    Mr. Middleton offers these examples, often cited by abiotic oil supporters, and declares they are not evidence of abiotic oil (with no supporting reasons or argument).

    With due respect to the valuble contributions to the discussions via Mr. Middleton’s posts on Watts Up With That?, those are all field observations which do support Abiotic Oil Theory.

    Mr. Middleton disagrees with the conclusions of other scientists and observers these are evidences of abiotic oil production in the Earth’s crust, but his statement is slightly misleading because he fails to acknowledge many others do agree the above field observations support the conclusion of abiotic oil production in the Earth’s crust.

    Due to the build up of scientific evidence supporting Abiotic Oil Theory, many oil geologists who subscribe to the “fossil” theory, acknowledge abiotic oil is produced here on Earth, but claim it is only produced in small amounts. But, if petroleum is produced via the Fischer-Tropsch Type process, the Fischer-Tropsch process known as the serpentinite mechanism or the serpentinite process, a geo-chemical process (a well constrained and quantified process, not “mythical” at all), then what is the limiting factor? That is never answered because there is no limiting factor beyond the availability of the building block elements in the Earth’s crust.

    Just one example of an oil geologist who supports abiotic oil theory: Peter Szatmari, an oil geologist, who works for Petrobas, the Brazilian state oil company, and it was Szatmari who predicted there would be oil offshore of Brazil in a 1989 scientific paper, based on abiotic oil principles, and yes, subsequently oil was found in world-class deposits right where Szatmari predicted.

    Szatmari noted in his 1989 paper that Fischer-Tropsch synthetic oil matches the hydrocarbon distribution profile of of Saudi Arabian oil fields.

    Petroleum Formation by Fischer-Tropsch Synthesis in Plate Tectonics, by Peter Szatmari (1989)

    Szatmari wrote:
    “COMPARISON OF NATURAL AND SYNTHETIC OILS
    Several constituents of petroluem indicate that it may have formed by Fischer-Tropsch synthesis. Crude oils, like oils produced by Fischer-Tropsch synthesis, are mixtures of a very large number of hydrocarbon compounds whose chain length ranges from one (methane) to many carbon atoms. In petroleum, as in the products of Fischer-Tropsch synthesis, the number of molecules systematically decreases with increasing number of carbon atoms, reflecting the probabilities of chain growth and chain termination that characterize any polymerization process (Schulz-Flory distribution) (Figure 1). Early studies by Robinson (1963) and Friedel and Sharkey (1963, 1968) indicate that the distribution of normal and isoparaffins in crude oil follows the chain-growth and chain-branching probabilities of the Fischer-Tropsch synthesis.”

    Szatmari wrote:
    “Friedel and Sharkey (1963, 1968) found that the two parameters of the Fischer-Tropsch synthesis — the probability of chain lengthening and that of chain branching — accurately predict the abundance of isomers in Saudi Arabian oil, suggesting that it formed by Fischer-Tropsch synthesis and not by thermal breakdown of fossil organic matter.”

    Perhaps, Mr. Middleton would like to review Szatmari’s scientific paper:

    http://www.scribd.com/doc/4653669/Petroleum-Formation-by-FischerTropsch-Synthesis-Peter-Szatmari

    Remember, Szatmari predicted the Brazilian offshore oil deposits using abiotic principles when nobody else thought there could be oil in those geological conditions using the “fossil” theory model.

    “Evidence” of significant volumes of abiotic oil would consist of a significant volume of oil in a setting in which there was no sedimentary source rocks present. No examples of such exist anywhere on Earth or, as far as we know, in the solar system.
    “The Dnieper-Donets basin is often cited as an example of abiotic oil due to a lack of source rocks. This is simply wrong: Petroleum Geology and Resources of the Dnieper-Donets Basin, Ukraine and Russia.
    The fractured granite reservoirs of the Cuu Long basin are often cited as an example of abiotic oil because oil is produced from fractured basement (granite) rocks. Oil is produced from Oligocene granite wash (yellow/green) on the flanks and top of a granitic diapir (pink) and from Miocene-Oligocene sandstones above the diapir. Oil is also produced from fractures in the granite (black/dark gray). The Oligocene shale (lighter gray with dashes) between the granite and the Miocene-Oligocene sandstones is loaded with organic matter. The oil that is produced from the granite wash, granite fractures and the shallower sandstones is geochemically indistinguishable and can be matched to the organic rich shale source rock. Petroleum Geology of Cuu Long Basin – Offshore Vietnam. The biotic hypothesis says that the oil formed in the shale and then migrated into the granite wash, granite fractures and overlying sandstone. The abiotic hypothesis says that the oil formed in the mantle and migrated up through the granite and then into the sedimentary rocks above and around the diapir, leached organic matter out of the shale and migrated back into the granite.

    Eugene Island Block 330 oil field is often cited as an example of abiotic oil because some reservoirs produced more oil that the volumetric analyses predicted. This happens all the time. Almost all reservoirs produce more or less oil than we predict. Our ability to accurately calculate reservoir volumes are limited to well control (often sparse) and seismic data (often of too low resolution). The abiotic stories about EI330 are nothing less than fantasies of science fiction. Eugene Island Block 330 Field–U.S.A. Offshore Louisiana. The “mysterious” increase in production from EI330 was the result of drilling.
    EI330 Production Rates
    EI330 Oil Production and Well Completions

    The ultra-deepwater Lower Tertiary play in the Gulf of Mexico and the deep subsalt plays offshore Brazil are often cited as examples of abiotic oil because the reservoirs are supposedly too deep, too hot and/or too highly pressured to be in the oil window. This is simply abject nonsense…

    Subsalt seen as promising exploration frontier for Brazil
    He argues that “up to some time ago, Petrobras believed that the subsalt rocks were too compacted, without permeability. However, with the confirmation of the Santos basin discovery, it was proved that the salt layer acts as a cushion for the compaction as well as for temperature.”

    Tabular salt acts like a radiator. It conducts heat away from the substrata toward the surface. The combination of thick layers of salt and deep water depths enable oil to exist at depths previously unexpected. Salt and water are also less dense than most other overburden. This enables reservoir quality rocks to exist at deeper depths than previously expected.

    The discovery well for the Cascade Field on WR 206 TD’ed with 15 pound mud at about 19,000’ below the seafloor (about -27,800 below sea level). 15 pounds at that depth is normally pressured. The bottomhole temperature was 246°F (~120°C), well within the oil window.
    Lost City and the Saturnian moon Titan are often cited as evidence of abiotic oil because they are evidence of abiotic methane. CH4 ≠Oil. When a mud log show consists solely of methane (C1’s), the hydrocarbons will generally consist of dry natural gas, with little or no liquids.

  4. David Middleton Says:

    James F. Evans says:
    September 2, 2012 at 1:16 pm
    David Middleton wrote the following were not evidence of abiotic oil:
    “The Dnieper-Donets basin.
    The fractured granite reservoirs of the Cuu Long basin.
    Eugene Island Block 330 oil field.
    The ultra-deepwater Lower Tertiary play in the Gulf of Mexico.
    The deep subsalt plays offshore Brazil.
    Lost City.
    The Saturnian moon Titan”

    Mr. Middleton offers these examples, often cited by abiotic oil supporters, and declares they are not evidence of abiotic oil (with no supporting reasons or argument).

    With due respect to the valuble contributions to the discussions via Mr. Middleton’s posts on Watts Up With That?, those are all field observations which do support Abiotic Oil Theory.

    Mr. Middleton disagrees with the conclusions of other scientists and observers these are evidences of abiotic oil production in the Earth’s crust, but his statement is slightly misleading because he fails to acknowledge many others do agree the above field observations support the conclusion of abiotic oil production in the Earth’s crust.

    Due to the build up of scientific evidence supporting Abiotic Oil Theory, many oil geologists who subscribe to the “fossil” theory, acknowledge abiotic oil is produced here on Earth, but claim it is only produced in small amounts. But, if petroleum is produced via the Fischer-Tropsch Type process, the Fischer-Tropsch process known as the serpentinite mechanism or the serpentinite process, a geo-chemical process (a well constrained and quantified process, not “mythical” at all), then what is the limiting factor? That is never answered because there is no limiting factor beyond the availability of the building block elements in the Earth’s crust.

    Just one example of an oil geologist who supports abiotic oil theory: Peter Szatmari, an oil geologist, who works for Petrobas, the Brazilian state oil company, and it was Szatmari who predicted there would be oil offshore of Brazil in a 1989 scientific paper, based on abiotic oil principles, and yes, subsequently oil was found in world-class deposits right where Szatmari predicted.

    Szatmari noted in his 1989 paper that Fischer-Tropsch synthetic oil matches the hydrocarbon distribution profile of of Saudi Arabian oil fields.

    Petroleum Formation by Fischer-Tropsch Synthesis in Plate Tectonics, by Peter Szatmari (1989)

    Szatmari wrote:
    “COMPARISON OF NATURAL AND SYNTHETIC OILS
    Several constituents of petroluem indicate that it may have formed by Fischer-Tropsch synthesis. Crude oils, like oils produced by Fischer-Tropsch synthesis, are mixtures of a very large number of hydrocarbon compounds whose chain length ranges from one (methane) to many carbon atoms. In petroleum, as in the products of Fischer-Tropsch synthesis, the number of molecules systematically decreases with increasing number of carbon atoms, reflecting the probabilities of chain growth and chain termination that characterize any polymerization process (Schulz-Flory distribution) (Figure 1). Early studies by Robinson (1963) and Friedel and Sharkey (1963, 1968) indicate that the distribution of normal and isoparaffins in crude oil follows the chain-growth and chain-branching probabilities of the Fischer-Tropsch synthesis.”

    Szatmari wrote:
    “Friedel and Sharkey (1963, 1968) found that the two parameters of the Fischer-Tropsch synthesis — the probability of chain lengthening and that of chain branching — accurately predict the abundance of isomers in Saudi Arabian oil, suggesting that it formed by Fischer-Tropsch synthesis and not by thermal breakdown of fossil organic matter.”

    Perhaps, Mr. Middleton would like to review Szatmari’s scientific paper:

    http://www.scribd.com/doc/4653669/Petroleum-Formation-by-FischerTropsch-Synthesis-Peter-Szatmari

    Remember, Szatmari predicted the Brazilian offshore oil deposits using abiotic principles when nobody else thought there could be oil in those geological conditions using the “fossil” theory model.

    “Evidence” of significant volumes of abiotic oil would consist of a significant volume of oil in a setting in which there was no sedimentary source rocks present. No examples of such exist anywhere on Earth or, as far as we know, in the solar system.

    “The Dnieper-Donets basin is often cited as an example of abiotic oil due to a lack of source rocks. This is simply wrong: Petroleum Geology and Resources of the Dnieper-Donets Basin, Ukraine and Russia.

    The fractured granite reservoirs of the Cuu Long basin are often cited as an example of abiotic oil because oil is produced from fractured basement (granite) rocks. Oil is produced from Oligocene granite wash (yellow/green) on the flanks and top of a granitic diapir (pink) and from Miocene-Oligocene sandstones above the diapir. Oil is also produced from fractures in the granite (black/dark gray). The Oligocene shale (lighter gray with dashes) between the granite and the Miocene-Oligocene sandstones is loaded with organic matter. The oil that is produced from the granite wash, granite fractures and the shallower sandstones is geochemically indistinguishable and can be matched to the organic rich shale source rock. Petroleum Geology of Cuu Long Basin – Offshore Vietnam. The biotic hypothesis says that the oil formed in the shale and then migrated into the granite wash, granite fractures and overlying sandstone. The abiotic hypothesis says that the oil formed in the mantle and migrated up through the granite and then into the sedimentary rocks above and around the diapir, leached organic matter out of the shale and migrated back into the granite.

    Eugene Island Block 330 oil field is often cited as an example of abiotic oil because some reservoirs produced more oil that the volumetric analyses predicted. This happens all the time. Almost all reservoirs produce more or less oil than we predict. Our ability to accurately calculate reservoir volumes are limited to well control (often sparse) and seismic data (often of too low resolution). The abiotic stories about EI330 are nothing less than fantasies of science fiction. Eugene Island Block 330 Field–U.S.A. Offshore Louisiana. The “mysterious” increase in production from EI330 was the result of drilling.

    EI330 Production Rates
    EI330 Oil Production and Well Completions

    The ultra-deepwater Lower Tertiary play in the Gulf of Mexico and the deep subsalt plays offshore Brazil are often cited as examples of abiotic oil because the reservoirs are supposedly too deep, too hot and/or too highly pressured to be in the oil window. This is simply abject nonsense…

    Subsalt seen as promising exploration frontier for Brazil
    He argues that “up to some time ago, Petrobras believed that the subsalt rocks were too compacted, without permeability. However, with the confirmation of the Santos basin discovery, it was proved that the salt layer acts as a cushion for the compaction as well as for temperature.”

    Tabular salt acts like a radiator. It conducts heat away from the substrata toward the surface. The combination of thick layers of salt and deep water depths enable oil to exist at depths previously unexpected. Salt and water are also less dense than most other overburden. This enables reservoir quality rocks to exist at deeper depths than previously expected.

  5. David Middleton Says:

    Steven Kopits says:
    September 3, 2012 at 6:26 am
    I hardly know where to start with David’s analysis. Is he in the business of producing such forecasts? His look like literally no one else’s, not the EIA, IEA, Citi’s, CERA’s, PIRA’s, or any of the leading lights over at the Oil Drum.

    The utilization rate for drillships and semisubmersibles in the Gulf of Mexico today approaches 100%. So the permatorium is over. Notwithstanding, if you look out at the actual project schedules for the Gulf to the visible horizon, there’s nothing there that really moves the production needle up much. Citi is bullish about the Gulf, but who else?

    […]

    If you bothered to read the post prior to commenting, you might have noted that I was not forecasting production. I clearly stated that I was looking at the technical feasibility and not the economic advisability or politic al achievability.

    Your comments on the Gulf of Mexico are amazingly ignorant. The “permitorium” is still in full effect. Simple applications, like development plans (DOCD’S) are being delayed by 10 months or more. The permitorium is forcing drilling contractors to relocate rigs overseas.

    Gulf of Mexico rig count ‘unsustainable’ without quicker permits: FBR
    Washington (Platts)–7Sep2011/315 pm EDT/1915 GMT

    Twenty deepwater drilling rigs would leave the Gulf of Mexico if US regulators do not accelerate permitting, investment bank FBR Capital Markets said Wednesday.

    The analysts blamed the Bureau of Ocean Energy Management, Regulation and Enforcement’s sluggish pace on higher safety standards enacted after the BP Macondo well blowout in April 2010, not politics.

    “Rather than being political, the GOM permitting drag is more reflective of the increased work required to issue each permit and the limited bureaucratic resources available,” the report said. “As a result, we continue to expect continued slow recovery of the deepwater permitting rate.”

    […]
    FBR called the active rig count — 20 at the end of August — “unsustainable” at the current pace of permit approvals. The Gulf of Mexico stands to lose eight to 20 rigs — eight if permitting speeds up and 20 if the pace stays the same.

    The report said the backlog of permits approved, but not acted upon needs to reach about 60 to support an active rig count of 20. Between 2006 and 2010, the industry had about three times the number of permits waiting for action than the number of deepwater rigs at work.

    […]

    The utilization rate for deepwater rigs & drillships is high, because 12 have left the Gulf since June 2010. If the permitorium continues, 20 more may leave the Gulf.

    In response to, “there’s nothing there that really moves the production needle up much”… Two years ago, the MMS forecasted that Gulf of Mexico oil production would 1.8 million barrels per day by 2013, much of that from the Lower Tertiary. That would move the needle up by almost 50% above the current ~1.3 million BOPD. Production from the Lower Tertiary discoveries was expected to begin in 2010. The first oil production from Petrobras’ Chinook-Cascade Field just commenced in February 2012.

    There have been 28 discoveries in the Lower Tertiary trend in Alaminos Canyon, Keathley Canyon and Walker Ridge areas since 2001. At least five of these discoveries will be on production within the next few years. The facilities will have an average production capacity of more than 100,000 BOPD. This will move the needle up. This play is in its infancy.

  6. David Middleton Says:

    Steven Kopits says:
    September 3, 2012 at 6:26 am
    I hardly know where to start with David’s analysis. Is he in the business of producing such forecasts? His look like literally no one else’s, not the EIA, IEA, Citi’s, CERA’s, PIRA’s, or any of the leading lights over at the Oil Drum.

    The utilization rate for drillships and semisubmersibles in the Gulf of Mexico today approaches 100%. So the permatorium is over. Notwithstanding, if you look out at the actual project schedules for the Gulf to the visible horizon, there’s nothing there that really moves the production needle up much. Citi is bullish about the Gulf, but who else?

    […]

    If you bothered to read the post prior to commenting, you might have noted that I was not forecasting production. I clearly stated that I was looking at the technical feasibility and not the economic advisability or politic al achievability.

    Your comments on the Gulf of Mexico are amazingly ignorant. The “permitorium” is still in full effect. Simple applications, like development plans (DOCD’S) are being delayed by 10 months or more. The permitorium is forcing drilling contractors to relocate rigs overseas.

    Gulf of Mexico rig count ‘unsustainable’ without quicker permits: FBR
    Washington (Platts)–7Sep2011/315 pm EDT/1915 GMT

    Twenty deepwater drilling rigs would leave the Gulf of Mexico if US regulators do not accelerate permitting, investment bank FBR Capital Markets said Wednesday.

    The analysts blamed the Bureau of Ocean Energy Management, Regulation and Enforcement’s sluggish pace on higher safety standards enacted after the BP Macondo well blowout in April 2010, not politics.

    “Rather than being political, the GOM permitting drag is more reflective of the increased work required to issue each permit and the limited bureaucratic resources available,” the report said. “As a result, we continue to expect continued slow recovery of the deepwater permitting rate.”

    […]

    FBR called the active rig count — 20 at the end of August — “unsustainable” at the current pace of permit approvals. The Gulf of Mexico stands to lose eight to 20 rigs — eight if permitting speeds up and 20 if the pace stays the same.

    The report said the backlog of permits approved, but not acted upon needs to reach about 60 to support an active rig count of 20. Between 2006 and 2010, the industry had about three times the number of permits waiting for action than the number of deepwater rigs at work.

    […]

    The utilization rate for deepwater rigs & drillships is high, because 12 have left the Gulf since June 2010. If the permitorium continues, 20 more may leave the Gulf.

    In response to, “there’s nothing there that really moves the production needle up much”… Two years ago, the MMS forecasted that Gulf of Mexico oil production would 1.8 million barrels per day by 2013, much of that from the Lower Tertiary. That would move the needle up by almost 50% above the current ~1.3 million BOPD. Production from the Lower Tertiary discoveries was expected to begin in 2010. The first oil production from Petrobras’ Chinook-Cascade Field just commenced in February 2012.

    There have been 28 discoveries in the Lower Tertiary trend in Alaminos Canyon, Keathley Canyon and Walker Ridge areas since 2001. At least five of these discoveries will be on production within the next few years. The facilities will have an average production capacity of more than 100,000 BOPD. This will move the needle up. This play is in its infancy.

  7. David Middleton Says:

    James F. EvansSep 5, 12:29 pm
    David Middleton:

    Thank you, I appreciate the answer. It is important to have dialogue, particularly when there is disagreement. I realize this thread is now long on the tooth, but I will give quick rebuttal. I don’t expect an answer, this for the record and for you to think about, assuming while you are reasonably sceptical, you still have an open-mind.

    Middleton wrote: “Evidence” of significant volumes of abiotic oil would consist of a significant volume of oil in a setting in which there was no sedimentary source rocks present. No examples of such exist anywhere on Earth or, as far as we know, in the solar system.”

    You make an a priori assumption that so-called “source rock” is the source of petroleum, but upon detailed investigation, it becomes apparent “source rock” can be explained with as much satisfaction, if not more satisfaction using abiotic principles.

    Middleton: wrote: “The Dnieper-Donets basin is often cited as an example of abiotic oil due to a lack of source rocks. This is simply wrong: Petroleum Geology and Resources of the Dnieper-Donets Basin, Ukraine and Russia.”

    False, nobody claim there isn’t sandstone, sedimentary rocks within the Dnieper-Donets basin with heavy hydrocarbons, C215H330. There are two major reasons for why it is cited as evidence for Abiotic Oil Theory:

    1.) There are multiple instances of petroleum being recovered from the crystalline basement below any so-called “source rock”, which in reality is simply porus rock, sedimentary, where heavy hydrocarbons are present, which is entirely consistent with the abiotic concept that as abiotic oil rises through vertical conduits, faults and fractures, a portion of the heavy hydrocarbon component of the petroleum drops out and lodges in those porus rocks (“fossil” theory explains the heavy hydrocarbons are produced by the so-called “diogenesis” process where organic detritus is turned into heavy hydrocarbons, so-called “kerogen”, actually C215H330, but “diogenesis” has never been demonstrated in the laboratory and there is no chemical pathway description, rather it is an unproven, a priori assumption, or as Mr. Middleton puts it, a “mythical” process).

    2.) The oil recovered from the crystalline basement has no evidence of organic detritus or so-called “bio-markers”.

    From the scientific paper The Drilling & Development of the Oil & Gas Fields in the Dnieper-Donetsk Basin, V. A. Krayushkin, T. I. Tchebanenko, V. P. Klochko, Ye. S. Dvoryanin, Institute of Geological Sciences, O. Gonchara Street 55-B, 01054 Kiev, Ukraine, J. F. Kenney, Russian Academy of Sciences – Joint Institute of The Physics of the Earth, Moscow, Russia (2001).

    Observation of petroleum in the crystalline basement:

    “Production from the Precambrian crystalline basement: In addition to these reservoirs in the sedimentary rock, above, the exploration drilling has discovered five reservoirs in the Precambrian crystalline basement rock complex at depths ranging from several meters to 200 meters below the top of the crystalline basement.”

    “The trapping strata for the reservoirs in the Carboniferous period sandstones are shallower shale formations, as is typical for sedimentary reservoirs. The trapping strata for the reservoirs in the Precambrian crystalline basement are impervious, non-fractured, essentially horizontal zones of crystalline rock which alternate with the fractured, uncompacted, bed-like zones of granite and amphibolite. An example of the “stacking of the petroleum reservoirs is shown in Fig. 2 for the Yuliyevskoye oil and gas field.”

    Observation of the lack of so-called “biomarkers” in the oil recovered from the crystalline basement:

    “Bacteriological analysis of the oil and the examination for so-called “biological marker” molecules: The oil produced from the reservoirs in the crystalline basement rock of the Dnieper-Donets Basin has been examined particularly closely for the presence of either porphyrin molecules or “biological marker” molecules, the presence of which used to be misconstrued as “evidence” of a supposed biological origin for petroleum. None of the oil contains any such molecules, even at the ppm level.”

    The USGS had no difficulty matching the Dnieper-Donets production to source rocks.

    Middleton wrote: “The fractured granite reservoirs of the Cuu Long basin [White Tiger offshore oil field, Vietnam] are often cited as an example of abiotic oil because oil is produced from fractured basement (granite) rocks. Oil is produced from Oligocene granite wash (yellow/green) on the flanks and top of a granitic diapir (pink) and from Miocene-Oligocene sandstones above the diapir. Oil is also produced from fractures in the granite (black/dark gray).”

    Yes, oil is produced from the fractures in the granite, as much as a thousand feet below the top of the fractures in the granite, which is a deep “rift” or fault, part of a rifted horst crystalline basement, which would act as a vertical conduit for abiotic sourced oil to rise up through.

    Mr. Middleton claims, “Oil is produced from Oligocene granite wash (yellow/green) on the flanks and top of a granitic diapir (pink) and from Miocene-Oligocene sandstones above the diapir.” But this statement is misleading, giving the impression equal amounts of oil are recovered from the surrounding ‘wash’ and ‘sandstone’ above the diapir. Rather, as the Search and Discovery paper cited by Mr. Middleton states, most oil is from the deep, ‘rift’ fracture, itself:

    “In spite of some discoveries in the Oligocene-Miocene clastics and volcanic sections, fractured granite basement is still the main target of Cuu Long basin. Tectonic activities play a key role in creating and enhancing the fractures in the basement. Five major oil fields produce predominantly from the basement [from within the faults].”

    They’re talking about how the granite became sufficiently fractured to have the porosity and permeability to become reservoir rock… Not how the oil got into the reservoir.

    Several characteristics of the faults and the petroleum recovered are significant:
    From the Search and Discovery:

    “The tops of these basement structures are usually at 2500 to 3000 mss with about 1000-1500 m [meters] oil column.”

    The oil column is extraordinarily tall, typically in the oil industry these are called “pay zone”.

    A large “pay zone” can be 300 feet, many are much shorter, reflecting the thickness of the sedimentary layer the oil is trapped in, but, here, it is over 3000 feet, (3,280 – 4,900 feet) in depth (once oil has been contacted), and that reflects the depth of the fault or ‘rift’, the extreme height of the oil columns is because the oil runs the full length of narrow vertical faults within the rifted horst, whereas, in average sedimentary oil deposits, the oil column is in the shape of a horizontal plane trapped below a horizontal cap rock that acts to seal the hydrocarbons in and prevent further rising within the stratigraphic column, so this is no ordinary oil column.

    Again, from the Search and Discovery paper:

    “However, the tectonic activity and the hydrothermal processes are practically the main factors that control the porosity of the fracture systems.”

    Hydrothermal systems have been identified as associated with oil deposits and specifically identified as an abiotic system where petroleum is formed by Fisher-Tropsch Type processes.

    (Which has already been discussed and a scientific paper presented and linked to without any comment or objection from Mr. Middleton.)

    Hydrothermal Hydrocarbons, Stanley B. Keith and Monte M. Swan (2005):

    “[Abiotic]…generation of methane and heavier hydrocarbons through reactions that occur during cooling, fractionation, and deposition of dolomitic carbonates, metal-rich black shales, and other minerals from hydrothermal metagenic fluids. These fluids are proposed to be the product of serpentinization of carbon-rich peridotites under hydrogen-rich, reduced conditions.”

    http://www.searchanddiscovery.com/documents/abstracts/2005research_calgary/abstracts/extended/keith/keith.htm

    (Another excellent paper for Mr. Middleton to review.)

    Again, from the Search and Discovery paper presented by Mr. Middleton:

    “This is the deepest basement structure in Cuu Long basin that has found oil. The DST flow rates from the main producing zone (4430 mss) are 2600 bopd, 6.8 mmscfgd, without water.”

    There is no highlight, but the notation, “without water” is very significant in terms of Abiotic Oil Theory. Typically oil is extracted with an accompaning ‘oil field brine’ a mix of water and oil (the water and oil are seperated after extraction) and various trace minerals and salt water (in Louisanna, ‘oil field brine’ extracted from around salt domes can have lead and strontium as trace metals). But in the White Tiger, Vietnam oil field there is no water, only pure petroleum.

    Why is that significant?

    Because water penetrates to the deepest part of any stratigraphic column as water is heavier than oil — oil floats on water.

    “Whether naphta was formed by organic matter is very doubtful, as it is found in the most ancient Silurian [Ordovician] strata which correspond with the epochs of the earth’s existence when there was very little organic matter; it could not penetrate from the higher to the lower (more ancient) strata as it floats on water (and water penetrates through all strata).” — Dmitri Mendeleyev, chemist, 1877

    If “water penetrates through all strata”, then, necessarily, if fluid (hydrocarbons) was penetrating from the “Upper Oligocene shale that is present throughout the basin and the Lower Oligocene interbedded shale” into the fractured rift network of the basement horst, water also would be penetrating into the rift fracture network. It could not be otherwise, yet in this case the hydrocarbons are specifically described flowing from the producing zone “without water”.

    Mr. Middleton wrote: “The abiotic hypothesis says that the oil formed in the mantle and migrated up through the granite and then into the sedimentary rocks above and around the diapir, leached organic matter out of the shale and migrated back into the granite.”

    First, the Fischer-Tropsch Type formation process referred to here several times with one scientific paper and one lengthy abstract of a scientific paper don’t claim the mantle as the source of abiotic oil (that is specifically the Russian-Ukraine primordial abiotic hydrocarbon theory), but rather from the deep crust where geophysical chemical reactions are known to take place and can be quite vigerous. And in the search and Discovery paper presented by Mr. Middleton, there is no reference or citation to “leached organic matter” within the White Tiger oil recovered from the actual deep fault — again, an unsupported assumption by Mr. Middleton.

    Good grief! Column height is dictated by seal integrity. It has nothing to do with sourcing. This is BASIC hydrodynamics.

    The lack of water in the drill stem test (DST) is also irrelevant to sourcing. Had the DST yielded a high water cut, it would have indicated that at least a portion of the perforation interval was in the water leg of the column.
    Maybe you missed the bit about the oil in the granite & granite wash having the same organic markers as the oil in the surrounding sandstones and matching the surround shale.

    Mr. Middleton wrote: “Eugene Island Block 330 oil field is often cited as an example of abiotic oil because some reservoirs produced more oil that the volumetric analyses predicted. This happens all the time. Almost all reservoirs produce more or less oil than we predict.”

    This is true, as far as it goes, but it is incomplete. First, the amount actually produced is at least an order of magnitude larger than the amount predicted. That is significant. Second, the oil well roughly produced its predicted amount and it did drop of dramatically in production, as expected, but suddenly, then began to produce in increased amounts almost equalling its original top production, and, it was evident the oil had a slightly different chemical “signature” from the original production and the oil was coming from deep below — Eugene Island Block 300 oil production was from the side of a salt dome.

    From the New York Times, September 26, 1995: “A geochemist at the Woods Hole Oceanographic Institution in Massachusetts says she believes that hitherto undetected gas and oil reservoirs lying at very great depths within the earth’s crust could stave off the inevitable oil depletion much longer than many experts have estimated.”

    “The scientist, Dr. Jean K. Whelan, whose research is part of a $2 million Department of Energy exploration program in the Gulf of Mexico south of New Orleans, has found evidence of differences in the composition of oil over periods of time as it flows from greater to shallower depths. By gauging degradative chemical changes in the oil resulting from action by oil-eating bacteria, she infers that oil is moving in quite rapid spurts from great depths to reservoirs closer to the surface.”

    It is important to note this is consistent with Abiotic Oil Theory because it suggests the oil rises up from depth though various vertical conduits, cracks in the crust.

    “This means that the active portions of the Northern Gulf of Mexico basin are acting like a giant flow-through system. As soon as oil or gas is generated, most is expelled into the Gulf waters. Only crumbs are retained in the basin (outside of the source). These crumbs are still of great economic value. What’s happening today (or in geologically very recent times) is what is important. As stated eloquently by Gatenby (2002), “in the Gulf of Mexico, the present is the …” — L. M. Cathles, Hydrocarbon generation, migration, and venting in a portion of the offshore Louisiana Gulf of Mexico basin (2004).

    The news articles about EI 330 from the late ‘90s are nonsense. I have the production data right in front of me. I work the freaking Gulf of Mexico for a living. I have access to all of the production data through OWL.

    The rejuvenation of EI330 field was entirely due to a drilling program in the mid-1990’s. Field production peaked at over 96,000 BOPD in 1976. By 1990 it had declined to about 17,000 BOPD. Between 1990 and 1994, they drilled and completed about 25 new wells and sidetracks… And by 1996, production was back up to more than 33,000 BOPD. Since 1994, the field production has steadily declined to just over 9,500 BOPD. It’s a big field, one of the biggest in the Gulf. But, it’s declining just as all fields do.

    The correlation between well completions and production (block 330 only) is highly significant (R² = 0.6861).

    So-called “fossil” theory claims the organic detritus responsible for the formation of petroleum was deposited millions of years ago, and the oil formed by the so-called “diogenesis”/”catagensis” process over the course of unknown millions of years (a totally unconstrained and unverified hypothesis) and then the oil stored millions of years ago, waiting for extraction. But, if the Gulf of Mexico is a giant “flow-through system”, and, indeed, naturally occuring oil slicks happen all the time and it is estimated “half an ‘Exxon Valdez’ of oil leaks or ‘seeps’ into the Gulf of Mexico every year, then if the oil has been stored in sedimentary trapping deposits, which leak or ‘seep’, then, by now, millions of years later, all the oil, by that constant action of leaking to the surface, would have drained the deposits. This is a significant falsification of the so-called “fossil” theory of petroleum formation. On the other hand, the Abiotic Oil Theory has a ready explanation for the present deposits: The oil was not necessarily formed ‘millions of years ago’, but more recently (and long ago), via geo-physical processes, that are still ongoing at some unknown rate, so there would be plenty of oil to account for the seeps (which has been happening for a long time as suggested by the animal life that has evolved to eat the oil seeping form the seafloor).

    The evidence for the widespread deposition of kerogen-forming organic-rich shale formations from the Late Jurassic through the Eocene is massively well-documented. The Cretaceous, in particular, was a “hydrocarbon kitchen.”

    While the exact process is not perfectly understood, the matching of oil to source rocks is extremely well-constrained in most cases.

    Mr. Middleton wrote: “The ultra-deepwater Lower Tertiary play in the Gulf of Mexico and the deep subsalt plays offshore Brazil are often cited as examples of abiotic oil because the reservoirs are supposedly too deep, too hot and/or too highly pressured to be in the oil window. This is simply abject nonsense…”

    False. It does violate the so-called “oil window” corollary of the “fossil” theory by its own terms.

    The oil is much hotter that 246°F. The oil is reported to be as hot as 500°F in the subsalt deposits off the Brazilian coast and as hot as 435°F in the deepest deposits in the Gulf of Mexico.

    A rough statement of theso-called “oil window” corollary:

    ” But there is a problem with this: the temperatures at depths below about 15,000 feet are high enough (above 275 degrees F) to break hydrocarbon bonds. What remains after these molecular bonds are severed is methane, whose molecule contains only a single carbon atom. For petroleum geologists this is not just a matter of theory, but of repeated and sometimes costly experience: they speak of an oil “window” that exists from roughly 7,500 feet to 15,000 feet, within which temperatures are appropriate for oil formation; look far outside the window, and you will most likely come up with a dry hole or, at best, natural gas only. The rare exceptions serve to prove the rule: they are invariably associated with strata that are rapidly (in geological terms) migrating upward or downward.”

    There have simply been too many deep wells drilled both on land and on the seafloor, deeper than 20,000 feet to support the nonsense of the “oil window”.

    This is abject nonsense. I’ve drilled wells deeper than 20,000’ in the Gulf of Mexico. The bottom hole temperatures were in the range of 215°F (100°C). Ten wells in the Gulf of Mexico, drilled to true vertical depths greater than 20,000’ have each produced more than 20 million barrels of oil. The maximum bottom hole temperature (213°F) was encountered in the Mississippi Canyon (MC) 777 TF001 well, drilled by BP. The average bottom hole temperature of those ten 20 million barrel producers was 197°F.

    Walker Ridge 758 Chevron #1 is the deepest Gulf of Mexico oil producer; drilled to a TVD of 28,497’ in a water depth of 6,959’. It was completed in a Lower Tertiary Wilcox sandstone (26,831’ – 27,385’). The bottom hole temperature was 226°F.

    I have access to well logs, scout tickets and production data for every well ever drilled in the Gulf of Mexico. The only data I don’t have access to are competitors’ well logs less than 2-years old. There are no oil wells in the Gulf of Mexico with bottom hole temperatures outside of the oil window.

    And I have seen absolutely no evidence that any of the offshore Brazil reservoirs are outside of the oil window either.

    Mr. Middleton, I don’t expect an answer, but I hope you apply The Scientific Method: Be reasonably sceptical, but have an open-mind to evidence.

    The evidence is there, if you are willing to consider it. The “fossil” theory first stated in 1757 was a primitive guess at what caused “rock oil” and. But sadly it has not changed even though the best evidence currently available supports the Abiotic Oil Theory. The Earth is a geo-chemical factory, with literally thousands of minerals (minerals run in families), is it really a surprise that the Earth, due to the natural chemical affinity between the elements hydrogen and carbon, would produce hydrocarbons?

    Science fiction is not evidence.

    While abiotic oil formation is not impossible. All of the evidence you have cited for it is either false or the product of a wide range of scientific and factual ignorance

  8. David Middleton Says:

    James F. Evans says:
    September 5, 2012 at 5:32 pm
    Mr. Middleton, Thank you for your answers.

    Is Peter Szatmari, who works for Petrobas, the Brazilian state oil company, engaging in “science fiction”? Are Stanley B. Keith and Monte M. Swan engaging in “science fiction”?

    The science fiction comment was more directed at the Eugene Island 330 and Lower Tertiary Gulf of Mexico claims.

    Szatmari was simply wrong. His hypothesis was tested by the discovery of subsalt oil reservoirs offshore Brazil. These reservoirs falsify his hypothesis.

    The subsalt oil reservoirs are easily tied to organic rich source rocks and the pressures & temperatures are well within the oil window for the same reasons as the ultra-deepwater subsalt plays in the Gilf of Mexico. It’s irrelevant whether or not Szatmari predicted oil would be found in this play based on abiotic principles. The oil that was discovered fully conforms to the conventional theory of oil formation.

    The only offshore Brazil reservoirs with bottom hole temperatures in the 350-450°F range are gas reservoirs.

    James F. Evans says:

    Are the Russian Scientists “engaging in “science fiction”?
    Are Proskurowski, Lilley, Seewald et. al. engaging in “science fiction”?

    According to the USGS, they are. However, let’s just say that it’s a coin toss. The Dnieper-Donnets might be an example of abiotic oil; however the presence of abundant sedimentary source rocks makes it impossible to test this hypothesis. How can it be tested? Drill a well in a fractured igneous rock formation, totally remote from any possible sedimentary organic sourcing… Say, the Siljan Ring.

    Ooops… Another abiotic hypothesis falsified…

    Black asphaltenic-type material removed from the drillstem at 5945 m [19,505 ft] in Well Gravberg-1 from the Precambrian granite, Siljan, Sweden, was investigated to determine its origin. The chemical characterization showed that this material contains small amounts of hydrocarbons maximizing in the diesel range. No heavy hydrocarbons were identified, except for trace amounts of polycyclic aliphatics. From the chemical and stable isotopic characterizations, we concluded that the black gelatinous material is derived predominantly from the alteration of biodegradable nontoxic lubricant (BNTL) additives by caustic soda, admixed with diesel oil and trace amounts of polycyclic hydrocarbons from recirculating local lake water. No evidence for an indigenous or deep source for the hydrocarbons could be justified.

    […]

    Jeffrey & Kaplan, 1988

    James F. Evans says:

    See, Mr. Middleton, I’m not engaging in science fiction, I’m simply pointing out the work of scientists who disagree with you.

    So, really, you aren’t saying I’m engaging in science fiction, you are accusing other scientists of engaging in science fiction.

    I’m not accusing anyone of anything. However, anyone who asserts that Eugene Island 330 and the ultra deepwater Lower Tertiary play in the Gulf of Mexico are evidence of abiotic oil is either engaging in science fiction or too ignorant of the facts and the science realize how loony they sound.

    The ultra-deepwater Lower Tertiary oil discoveries are well within the oil window. The shallow water Lower Tertiary gas discovery at Davy Jones is well out of the oil window, in the gas window…

    Davy Jones to Cascade Cross Section
    Gulf of Mexico Lower Tertiary and the Oil/Gas Window

    And… Please don’t reply with, “But these wells are too deep to be in the oil window.” The hydrocarbon windows are temperature-dependent, not depth dependent. The depths on the chart are approximations based on a generalized geothermal gradient. The geothermal gradient is highly variable. Water and halite are less dense than most rocks. When the overburden consists of 8,000’ of seawater and 2,000’ of halite, 30,000’ of overburden weighs a lot less than it does when it’s all composed of more dense rocks.

    James F. Evans says:

    Considering you didn’t even address the Szatmari paper or its evidence, is it really proper to turn around and accuse him of engaging in science fiction?

    As I previously noted, the actual drilling of subsalt oil reservoirs offshore Brazil refuted the Szatmari paper and falsified his hypothesis…

    The Super Giant Sub-Salt Hydrocarbon Province of the Greater Campos Basin
    In most areas of the ultra deep waters from the Brazilian margin, exploration has just begun with the discovery of four of the biggest oil fields found in the world. The fields encompassing more than 20 Bbbls of oils of reserves are the Tupi, Jupiter, Guará and Iará, oil fields. This paper presents the results of petroleum system modeling that was run on a detailed 3D geological framework built on a 20,000 Km2 of the best 3D PSDM seismic data (CGGVeritas) ever performed in the Santos Basin and on proprietary geological and geochemical data of HRT & Petroleum. With the discovery of the supergiant pre-salt oilfields in the Santos Basin, the meaning of petroleum exploration in Brazil changed completely. The paradigm against the existence of super giant hydrocarbon fields, in the sub-salt sequence in the Greater Campos realm, has been destroyed. New discoveries in the same pre-salt province suggest that the Brazilian reserves are indeed much larger, close to 50 Bbbls. This paper comprises a 3D petroleum system modeling used to assess the interplay among source, reservoirs, seals and trap geometries, thermal evolution of source rocks, hydrocarbon types, charge, timing of migration, accumulation and oil quality and a volumetric quantification of the accumulated petroleum. The main results indicate the presence of an overcharged source rock system reaching almost 90% transformation in the main depocenters of the studied area. Also, low excess pressure and temperature values occur below salt, in the main carbonate reservoirs from the Upper Lagoa Feia Fm, and range from 0.3 to 0.4 MPa and 80° to 100°C, respectively. Such values are critical in preserving the oil prone nature of the whole area. In general the pressure behavior seems to reflect the distribution of the massive halite layer in the basin, indicating normal pressure for most of the area below salt. Also, the salt layer was key in sealing the escape of hydrocarbons upward. The reservoir rocks, composed by stromatolites, coquinas and vulcanoclastics sum more than 300 m in thickness and extend for more than 1500 km to the north, presenting porosities up to 18% and permeability ranging from 50 to 400mD. The supergiant accumulations are trapped below a huge salt layer that acted as the BEST preservation element possible (seal, cushion and temperature drainer). Such ideal conjunction of the elements and processes established one of the most prolific petroleum system of the world.

    Mello, et al., 2009
    80° to 100°C is well within the oil window.

  9. Niamh Says:

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