The meteoric rise never felt sustainable - the numbers told us that. In 2013, US shale was responsible for approximately 20 percent of world investment in oil, while only supplying four percent of global production. The figures today are even grimmer.
Baker Hughes is cutting 7,000 jobs; Halliburton, 6,500; Schlumberger, 9,000. The national oilrig count has sunk to a three-year low. Chevron is slashing its budget 13 percent relative to last year; ConocoPhillips, 20 percent; ExxonMobil prefers not to say for now. Pick a metric and I can find two that are trending downward. For US shale, this is largely a self-inflicted wound.
Up 80 percent since 2008, US oil production was never supposed to be here - not again at least. Booming production met an unprepared and reasonably saturated market and the rest is history, still in the making. West Texas Intermediate (WTI) is in the $50 - $52 per barrel range, and threatening lower as plays in the Bakken, Eagle Ford, and Permian basins continue to churn out more. A downturn is certainly on the way, but a complete shut in is largely out of the question. Instead, majors and independents alike are scrambling to do more with less, work smarter and not harder.
Necessity is often the mother of invention, but in the oil industry you still need time and money - both commodities as precious as the light tight oil (LTO) itself. Today, new wells can cost nearly $8 million, or twice as much as the average well just eight years ago. And, you'll need a lot of those. To maintain production of 1 million barrels per day, an LTO basin will require between 1,500 and 2,500 wells. For comparison, conventional production in Iraq can reach similar levels with fewer than 100 wells. In the past optimization was largely by trial and error - or "pump and pray" - but as the margin for error shrinks, it's back to drawing board.
An old, but increasingly interesting technique is the gas frack. More specifically, dry fracking, or gas fracking - which usually isn't dry - utilizes gas liquids or carbon dioxide (CO2) instead of water as the primary medium to create underground fissures. Of these gas liquids, butane, pentane, and propane are most commonly used. While certainly more dangerous, gas fracking requires less fluid by volume, does less damage to the formation, and the flowback material, once separated, can be sold as fuel. Still, fewer than 5 percent of all fracks were completed without water in 2012 - a number that perhaps speaks to its lesser commercial viability.
Fracking with CO2 may also get a second look. CO2-based fracks are believed to be more productive and obviously eliminate rapidly growing issues surrounding "produced" water, but any widespread adoption will require a helping hand. Irony aside, the Environmental Protection Agency (EPA) is a better candidate than most. A government mandated price on carbon and more stringent emissions limits - the latter already on the way - could create a robust market for captured CO2. Transportation presents a logistical nightmare, but the relatively environmentally friendly method will see more chances as public opinion continues to hound fracking.
The most likely solution to fracking's woes is more fracking. Re-fracking, as it's known, is essentially more of the same with some newly available technological twists. The trick is isolating areas missed, or not fully fractured, on the first go-round. Both Halliburton and Schlumberger are perfecting identification techniques and well-bound gadgets to achieve such ends. At approximately $2 million per well, re-fracking is the type of conservative, though novel, experimentation that pays. With nearly 50,000 existing candidate wells, the industry expects shale growth to continue to lead US production toward the end of the decade.
The International Energy Agency seems to agree. In their Medium-Term Market Report, the agency expressed its belief that US LTO will regain momentum in the lead up to 2020 and North America will remain a top source of supply growth globally. Down, but not out, shale returns to its roots - a period of a thin margins and heavy experimentation. Technology isn't the savior - low prices will continue to hit hard - but some innovative thinking and a little bit of the same will keep the industry afloat.
By. Colin Chilcoat of Oilprice.com
Colin Chilcoat is a specialist in Eurasian energy affairs and political institutions currently living and working in Chicago. A complete collection of his work can… More
Comments
At high oil prices operators needed only drill and frack more wells to service debt acquired on prior wells. Now those lenders are exposed in a big way.
Keep up the good work.
Plainly, technological advancements will benefit the oil industry immensely, but I don't think it's as bad as it's been laid out.
The problem is the cost of CO2.
So, if we are going to assume cheap CO2, it will find its most productive uses first and fracking will be farther down on the list.
The only way fracking is coming back is high oil prices (and it was questionable to begin with). When global production really starts to come down, and price really moves up, then it will be viable and sustainable (as long as the resources last).
Regards,
Cooter
CO2 on the other hand is capex heavy and with minimal results. We are fooling ourselves in saying CO2 capture And sequestration is Green. NOT So when you use CO2 to produce more CO2.
The answer has to be Ulatra Sound technology especially for EOR. Compare the cost to benefits. Under $8 per barrel compared to $30 + for CO2 EOR.
Output increases compare on an estimated average of 30% per well to 10-15% in comparison to Co2.
UST is clean, Green, mobile, economical, does not harm the well infrastructure and integrity and highly productive.
Again the North American oil patch will figure this out over the next two years. At that point all the no-frac countries will be racing to sell exploration rights to the vast potential of the tight shale formations not being drilled. What would it mean for the current valuations of those drillers who can effectively double their reserves? What about the countries in Europe that are dependent on Russian imports? This may be the one time US Foreign policy worked in the last 50 years.
Again the North American oil patch will figure this out over the next two years. At that point all the no-frac countries will be racing to sell exploration rights to the vast potential of the tight shale formations not being drilled. What would it mean for the current valuations of those drillers who can effectively double their reserves? What about the countries in Europe that are dependent on Russian imports? This may be the one time US Foreign policy worked in the last 50 years.