Before I update people on Europe, let’s not forget North America where it all began. One would think six years or so into the shale transformation that not much more shale gas and oil could be left. The story of the US is now becoming one of shale gas/tight oil plays developing in what were politely called mature areas, or garbage basins if not. These were places where oil production was down to as low as 2 barrels a day per well. At old oil prices that would barely pay for maintenance, but $200+ a day isn’t too bad. But going back and re fracking the well to make it produce a 200 barrels as they are doing all over the Permian Basin of West Texas for example is interesting money, even if the decline goes to a mere 40 after a few months.
A hundred here, a hundred there and soon you end up talking real money, and making a real contribution to US energy security given the amount of wells. But more is to come
Oil and gas producers are in the infant stages of a new liquids-rich play in the South Florida basin that could revive the oil industry in rural-agricultural parts of South Florida.
This part of Florida commenced conventional oil production in the early 1940s from the upper part of the self-sourced Sunniland formation, a porous, early Cretaceous limey marlstone. Peak production from this upper porous section (and for the basin) was reached in the mid 1970s at 17,000 b/d of oil, and since inception 120 million bbl have been produced from 14 fields that were full to spill point.
But we also have interest in Lousiana
Another liquids play that the Sunniland matches up with is the Tuscaloosa Marine shale, which is garnering recent industry attention.
Tuscaloosa marine shale land has been going for $600/acre for 5-year leases at 25% royalty.
Devon Energy and Encana Corp. have spent $120 million acquiring 400,000 acres of 3-year paid-up leases at $300/acre with 2 year extensions at $300/acre and 78% net revenue interest.
The primary zone of interest, a high log resistivity (5+ ohms) zone, is located at the base of the Tuscaloosa Marine shale section and is found at about 12,500 ft.
Conventional production from this section was established in 1992 by a vertical well in Tangipahoa Parish of southeastern Louisiana. This well has produced more than 20,000 bbl of oil with no water at a rate of 1-2 b/d for the last 19 years.
I’ve mentioned the New Albany Shale in Southern Illinois before. What’s the latest there?
The scale at which these companies want to develop the New Albany formation is massive. To make their investment worth the fortune they expect to spend in drilling and production costs and the millions they’ve already spent for mineral rights — these companies must have a lot of land under lease before they even think about drilling the first well. One estimate is they plan to have 1.5 million acres under lease before it’s all over.
If another oil boom is about hit Southern Illinois — it will be vastly different from earlier ones from a technological standpoint.
First of all, producers will likely utilize horizontal drilling techniques. Since the New Albany pay isn’t all that thick, they will have to drill down to the target formation — magically turn the drill bit and auger into the New Albany lengthwise. The formation will most likely have to be “fractured” as well to release the oil and gas.
But we don’t want to give you that. California oil production was once only second to Texas, then got overtaken by Alaska and recently has been humbled by North Dakota:
The crude explosion in the Bakken fields is by now a well-traveled story. In 2011 alone, North Dakota crude production jumped from 341,000 b/d to 535,000 b/d at year’s end. That trend is expected to continue. In fact, the state is seen as now chasing second place producer, Alaska, which produced an onshore average 611,000 b/d in December.
Yet California has–in addition to giant conventional oil fields–its own shale play with even greater potential: The 1,752-square-mile Monterey formation, which the EIA pegs at 15.42 billion barrels of technically recoverable oil, is the largest such play in the US.
Yet all shale plays are not created equally. Whereas the Bakken is relatively uniform, the Monterey is rather amorphous, requiring lots of trial and error. The result is a frustrating learning curve that has bedeviled many independents.
“That’s the nature of unconventional plays,” said Phil McPherson, a partner and senior analyst with Global Hunter Securities. He remains bullish on California, noting that Occidental Petroleum, the largest holder of Monterey shale acreage has had success in the play.
And while other companies struggle with the Monterey, he said, don’t forget that the Bakken took several years to figure out in the early- to mid-2000s before emerging as a star producer, he notes. It’s just a matter of time for the Monterey.
Finally that time has already come for the Eagle Ford. I can’t find the date of when I published the Eagle Ford graph which showed a massive 21.8 million barrels of production in January through November 2011, but this the final figures for 2011, showing production growing at 9 million barrels per month