By David Middleton – Re-Blogged From WUWT
The plots of the Seinfeld TV show often revolved around trivializing important things and blowing trivial things out of proportion. While not a Seinfeld fanatic (I’m more of a Frasier fanatic), I thought the comedy routines were generally brilliant and quite effective.
Peak Oil, abiotic oil and EROEI (energy returned on energy invested) are largely academic concepts. They are the subject of books, academic publications and Internet “debates” The “debates” about Peak Oil, abiotic oil and EROEI are a lot like the Seinfeld show. They magnify the trivial and trivialize things that actually matter. The “debates” often divide into two camps:
- It’s the end of the world (Peak Oil, EROEI).
- It’s our salvation from the end of the world (Abiotic oil).
While all three of these energy-related topics are, at least to some extent, real, none of them have the slightest relevance to energy production… except for Peak Oil… But the relevance is generally missed by both sides in Internet “debates.”
I had originally intended on combining Peak Oil, abiotic oil and EROEI into one post; but realized that it would have been longer than Tolstoy’s War and Peace. So, this post will be limited to Peak Oil. Part Deux will deal briefly with abiotic oil and Part Trois will deal more extensively with EROEI.
Peak Oil: A Real Thing That Doesn’t Matter
What is Peak Oil?
In its simplest form, “Peak Oil” is the point at which petroleum production reaches its maximum rate. It is based on the work of Shell geologist M. King Hubbert (Hubbert, 1956). It’s simply a mathematical approximation of how the production rate of oil, gas or any other depleting resource will change as the resource is recovered. Hubbert’s logistic function yields a maximum production rate at the time half of the resource has been produced. Reality is messier than this; but Hubbert’s logistic function is a decent approximation, particularly for regional analyses. In its most common form, “Peak Oil” is applied to oil producing regions, nations and the world.
This was Hubbert’s 1956 “forecast” for Peak Oil in the US:
Peak Oil is highly dependent on the total volume of a resource that will be recovered. Note how the “peak” moves forward in time as the total volume of recoverable oil is increased. Hubbert’s forecast wasn’t looking too bad as recently as recently as 2008. However, the recoverable resource was much larger than 150 or 200 billion bbl.
Through 2017, cumulative production totaled over 222 billion bbl and proved reserves stood at just under 40 billion bbl.
In order to estimate when US Peak Oil will occur (or has occurred), we would need to know how much of the oil resources, not classified as proved oil reserves, will be recovered. At best, this is a SWAG. The Bureau of Ocean Energy Management (BOEM) estimates that there are about 90 billion bbl of technically recoverable oil remaining on the US Outer Continental Shelf (OCS). Until proved reserves and the estimated undiscovered resource begin to decline, it will be impossible to forecast Peak Oil.
How do we know that Peak Oil is real?
Let’s start out with a simple, generalized depiction of an oil reservoir.
Every oil well, every reservoir and every oilfield has or will reach a peak oil production rate, followed by a steady decline. The rate of decline and recovery rate are generally functions of the reservoir drive mechanism.
The reservoir drive mechanism supplies the energy that moves the hydrocarbon located in a reservoir container toward the wellbore as fluid is removed near the wellbore. There are five common drive mechanisms:
Rock or compaction drive
One type usually dominates, but drive types can occur in combination. Depending on the drive mechanism, characteristic recovery efficiencies can be expected for a given reservoir.
When an oil and/or gas well is completed, the production casing is perforated at the level of the reservoir. The virgin reservoir pressure is considerably higher than the pressure in the wellbore. This causes the oil and/or gas to flow into the wellbore and to the surface. As the oil and/or gas are removed (voided) from the reservoir a combination of two things generally occurs.
- The reservoir pressure begins to decline.
- Formation water begins to move up-dip.
Water drive and gas expansion (pressure depletion) drives are the most common drive mechanisms. One feature shared by all drive mechanisms is that the maximum production rate occurs early in a well completion’s life cycle.
A water drive reservoir will exhibit increasing water production as oil production declines. The oil is “swept” up-dip as the water table rises to accommodate voidage of the oil. Strong water drives are the best oil reservoirs; but not very good gas reservoirs.
Gas solution (pressure depletion) drive reservoirs will exhibit a drop in reservoir pressure and an increase in the gas:oil ratio (GOR) as the oil production rate declines. These are poor-performing oil reservoirs; but the best performing gas reservoirs.
The drive mechanism determines how much of the original oil in place (OOIP) can be recovered:
|Energy Source||Recovery (% OOIP)|
|Evolved solution gas expansion||5–30|
|Gas cap drive||Gas cap and evolved solution gas
|Water drive||Aquifer expansion||35–75|
These percentages can be increased through secondary (water flood) and tertiary (carbon dioxide injection) methods. Future technological advances will probably lead to improved recovery rates. However, 100% recovery rates are highly improbable.
Oifields are groups of well completions in reservoirs. They behave much like the individual reservoirs do. All oifields eventually peak, as will global oil production. When will this happen? I have no idea.
Eugene Island 330 was once the largest field in the US Gulf of Mexico in total oil & gas production (BOE). Although it has been surpassed by Shell’s deepwater Mars field, it is still one of the biggest oilfields in the Gulf and the largest (BOE) field on the shelf (<1,000′ water depth).
Eugene Island 330 field has produced almost 500 million bbl of oil and 1.9 TCF (trillion cubic feet) of gas from September 1972 through January 2019. The field averaged 8,200 bbl/d in 2018. Note how the production ramped up quickly, peaked and then tailed off slowly.
When we look at the aggregate oil production from US Gulf of Mexico shelf, we can see a Hubbert-like pattern:
The US Gulf of Mexico shelf has passed “Peak Oil.” An opening of the Eastern Gulf of Mexico to E&P operations would probably yield a short resurgence in oil production; but in terms of oil production, the shelf is in permanent decline. There is still a lot of potential for gas on the shelf; but much of this is uneconomic at today’s natural gas prices. Fortunately, the Gulf of Mexico doesn’t stop at a water depth of 1,000′.
The thing about “Peak Oil” is that there are many different types of peaks.
Peak Oil in the Williston Basin of North Dakota appears to have occurred in 1985:
Then the oil industry, largely led by Continental Resources, figured out how to economically produce oil from one of the basin’s most prolific source rocks, the Bakken formation.
The Bakken was a key factor in the “shale revolution.” Hubbert’s 1956 Peak Oil forecast for the US looked pretty good before the “shale revolution.”
Oil production from the North Slope of Alaska peaked in 1990, due to the fact that ANWR Area 1002 and the Beaufort & Chukchi Sea OCS (outer continental shelf) areas have been generally inaccessible for political reasons.
How do we know that Peak Oil doesn’t matter?
Oilfields, like individual reservoirs, generally exhibit exponential decline curves. The decline curve flattens out over time. The average decline rate for mature oilfields is about 5%. Giant oilfields average about 3% decline rates.
However, this is not the only reason for the slow tail off. Most of the capital expenditures occur early in the life of an oil discovery. Once the field is online, the cash flow from the oil & gas production only needs to cover the costs of operating the field. Furthermore, the cost to plug and abandon (P&A) a field can be quite expensive, particularly for offshore fields. Continuing to operate a cash flow-negative oilfield is economically preferable to incurring the P&A costs.
The North Slope of Alaska is an example of this. Production from the giant Prudhoe Bay oilfield ramped up very quickly, peaked in 1990 and tailed off.
The Trans-Alaska Pipeline System (TAPS) can’t function below a rate of 200,000 bbl/d. Operators of North Slope oilfields have a very powerful incentive to maintain production rates well-above 200,000 bbl/d.
When global Peak Oil actually occurs, it will probably be driven by demand, rather than supply. The supply is ample and diverse. Note the impact that the decline of the largest oilfield in the world, Saudi Arabia’s Ghawar, and the collapse of Venezuela’s oil production have had on global oil production:
Dean Wormer would describe the impact as…
Inflation-adjusted oil prices have exhibited no statistically significant trend over the past 50 years.
The “shale revolution” coincided with the 2006-2014 period of generally high oil prices. It’s often said that $100/bbl oil was a bigger factor than horizontal drilling and frac’ing. This is true to a point. However, the collapse in oil prices since 2014 forced the shale players and the rest of the oil industry to reduce costs… And the industry did this “with a vengeance.”
EOG Resources, the leading shale player nationwide, has generated positive operating cash flow every year since 2014 and positive free cash flow in 2014 and 2017-2018.
Chevron, the top US oil producer and major Permian Basin player has generated positive operating cash flow every year since 2014 and positive free cash flow 2017-2018.
It was actually more difficult for shale players to generate free cash flow with $100+ oil prices than it has been at $50-60/bbl. $100+ oil made it almost impossible to control spending. The drop from $100-$30/bbl made it worse. However, the drop in prices created leverage to reduce costs, particularly rig rates and service company expenses. Everyone, conventional and unconventional players alike, ratcheted down spending from 2015-2017. Breakeven prices for the shale plays plummeted over this period.
Note: Unconventional oil is often no different than conventional oil. The Bakken shale was the source rock for many conventional migrated oil accumulations trapped in porous and permeable sandstone and carbonate reservoirs in the Williston Basin. The “unconventional” aspect is in the use of horizontal wells and massive frac jobs to enable oil production directly from the low permeability source rock.
When oil prices go up, costs go up. Everything from rig day rates, to frac fluids & sand, to offshore workboats, to motel rooms in the Permian Basin. $100 oil kicked off the “shale revolution”… But wasn’t necessary to sustain it.
Over the last couple of years, E&P companies have become more efficient, forced to create investor returns at $40 – $50/barrel oil. Well productivity has improved as companies drilled longer laterals and used less proppant. After the crash in oil prices, oilfield services companies lowered their prices to compete for limited work. As oil prices recovered, the price of oilfield services was slow to catch up. Additionally, companies have more capital discipline than they ever did at $100/barrel oil prices.
Even as oil prices have started to recover, companies are showing lower breakeven costs than ever before. As shown in the chart below, breakeven prices in the Midland Basin fell by 50% from $87 in January 2014 to $44 in September 2018.
The cost-cutting was industry-wide:
Breakeven prices have been reduced onshore and offshore, conventional and unconventional.
Industry has no control over prices; but can always reduce costs by doing things more efficiently. This is why deepwater Gulf of Mexico E&P is booming at $50-60/bbl oil prices:
Most oil companies make final investment decisions (FID) based on the current price of oil, adjusted for the expected inflation rate over the anticipated project duration. High oil prices drew the industry to shale plays like the Bakken and Eagle Ford and out into deepwater. The industry’s “learning curve” made those plays even more economically viable at $60/bbl than they were at $100+/bbl. Peak Oil, as real as it is, simply doesn’t matter.
As long as oil prices continue to climb at least as fast as the inflation rate, the industry will be able to meet the demand for refinery and petrochemical feedstocks for a long time to come… And North America is well-positioned to dominate the 21st Century.
Bear in mind that I did not factor in natural gas and most of the production data I used did not include natural gas liquids (NGL). Natural gas resources are even more abundant than crude oil and can, to some extent, serve as a replacement… Rendering Peak Oil even more irrelevant.
To Be Continued
Part Deux will address the real(ish) nature of abiotic oil and its irrelevance.
Part Trois will address the real(ish) nature of EROEI and its Seinfeldian position among irrelevant things.
About the Author
I have a B.S. degree in Earth Science (1980) from “that fine oil school,” Southern Connecticut State University. I have been employed in the US oil & gas industry as a geophysicist/geologist since 1981, mostly working the Gulf of Mexico for companies you probably never heard of.