Recently in Unconventional Resources Category
There are always nay-sayers who predict that the current boom, whatever it may be, will soon be a bust. Recently, however, some pretty prominent voices have cautioned that all of the rosy predictions about the future of the shale boom, US energy independence, and the continued growth of US oil and gas production are false - a bubble soon to burst.
One of those is J. David Hughes, a geoscientist with the Post-Carbon Institute. He spent 32 years with the Geological Survey of Canada, and coordinated an assessment of Canada's unconventional natural gas potential. He has authored "Drill, Baby, Drill," published last year by the Post Carbon Institute and the Energy Policy Forum. It is a pretty comprehensive review of the long-term viability of the shale plays. Some excerpts:
- "World energy consumption has more than doubled since the energy crises of the 1970s, and more than 80 percent of this is provided by fossil fuels. In the next 24 years world consumption is forecast to grow by a further 44 percent--and U.S. consumption a further seven percent--with fossil fuels continuing to provide around 80 percent of total demand."
- "Shale gas production has grown explosively to account for nearly 40 percent of U.S. natural gas production; nevertheless production has been on a plateau since December 2011 --80 percent of shale gas production comes from five plays, several of which are in decline. The very high decline rates of shale gas wells require continuous inputs of capital--estimated at $42 billion per year to drill more than 7,000 wells--in order to maintain production. In comparison, the value of shale gas produced in 2012 was just $32.5 billion."
- "Tight oil plays are characterized by high decline rates, and it is estimated that more than 6,000 wells (at a cost of $35 billion annually) are required to maintain production, of which 1,542 wells annually (at a cost of $14 billion) are needed in the Eagle Ford and Bakken plays alone to offset declines. As some shale wells produce substantial amounts of both gas and liquids, taken together shale gas and tight oil require about 8,600 wells per year at a cost of over $48 billion to offset declines. Tight oil production is projected to grow substantially from current levels to a peak in 2017 at 2.3 million barrels per day. At that point, all drilling locations will have been used in the two largest plays (Bakken and Eagle Ford) and production will collapse back to 2012 levels by 2019, and to 0.7 million barrels per day by 2025. In short, tight oil production from these plays will be a bubble of about ten years' duration."
Hughes' report is filled with graphs illustrating production and consumption world-wide and by field. Here is an example:
The Haynesville, Barnett, Fayetteville, and Woodford plays, which collectively produce 68 percent of United States shale gas, are late-middle-aged in terms of the life cycle of shale plays. Unless there is a substantial increase in gas price and a large ramp-up in drilling, these plays will go into terminal decline. The prognosis for the top nine shale plays in the United States, which account for 95 percent of shale gas production, is presented in Table 2.
Hughes also discusses the two biggest oil shale plays, the Bakken and the Eagle Ford. Together, these fields produce more than 80 percent of tight oil production in the US. "Overall field decline rates are such that 40 percent of production must be replaced annually to maintain production."
Given the EIA estimate of available well locations, the Bakken, which has produced about half a billion barrels to date, will ultimately produce about 2.8 billion barrels by 2025 (close to the low end of the USGS estimate of 3 billion barrels). Similarly, the Eagle Ford will ultimately produce about 2.23 billion barrels, which is close to the EIA estimate of 2.46 billion barrels. Together these plays may yield a little over 5 billion barrels, which is less than 10 months of U.S. consumption.
Some figures from Hughes' discussion of the Eagle Ford:
"The future production profile of the Eagle Ford--assuming a total of 11,406 effective locations, a 40 percent overall field decline, and current rates of drilling with all new wells performing as in 2011--is illustrated in Figure 75. This yields a production profile which rises 34 percent from June 2012 levels to a peak of 0.891 million barrels per day in 2016 as illustrated in Figure 75. At this point, with all well locations drilled, production declines at the overall field decline rate of about 40 percent. The overall field decline may decrease somewhat over time after peak as wells approach terminal decline rates. This also assumes that 70 percent of the wells drilled to date have targeted the oil-rich portion of the
Eagle Ford play. Total oil recovery in this scenario is about 2.23 billion barrels by 2025, which agrees quite well with the EIA's estimate of 2.46 billion barrels.157 Average well production falls below 10 bbls/d in this scenario by 2021."
Hughes' report provides a wealth of data and puts the "shale boom" in perspective. He may be overly pessimistic, but he certainly makes one think about the world's unsustainable thirst for hydrocarbons.
I ran across an article in the New York Times about a new publication, "The Boom," becoming popular with oil field workers in the Eagle Ford. It's a good read. And it's free online. Check out the article in the August publication, "Eagle Ford Shale Takeaways." It's a reprint of an article from Drillinginfo, based on Drillinginfo's analysis of several thousand wells in the Eagle Ford play. One conclusion from that article:
The very best Eagle Ford Shale operators produce 30% to 40% better than the median FOR THE SAME QUALITY OF ROCK, and they produce three times as much as operators at the low end. ... The implications for mineral owners in this scenario are obvious. Massive gaps in production naturally lead to large gaps in royalty payments. A 25% royalty lease with an average operator is equivalent to an 18% royalty lease with the best operators. That same lease with the worst operators is the same as an 8% lease with the best.
Also check out Texas Eagle Ford Shale Magazine, another digital publication catering to the Eagle Ford play.
Here are two emerging technologies that could change how we might use natural gas to fuel our cars and electrify our homes and offices.
A company called Redox Power Systems is building a plant in Florida to produce The Cube, a dishwasher-sized system that generates electricity from natural gas using electro-chemical fuel cell technology.
With almost no moving parts, The Cube can provide enough electricity to power a gas station or a small grocery store. It also generates heat that can be used to heat a home or business. It's technology was developed at the University of Maryland. The system also emits carbon dioxide, but according to a review by MIT, its emissions should be lower than those associated with power from the grid. Redox plans to complete a 25-kilowatt prototype and start selling complete systems by the end of this year.
A company named Siluria Technologies is making low-carbon gasoline from natural gas using a catalyst grown from a genetically modified virus. Siluria claims that its gasoline carries half the carbon footprint of gasoline refined from oil, and that it can produce gasoline for about $15 a barrel, not counting the price of the natural gas consumed. According to Sliuria's website: "At commercial scale, Siluria's process will enable refiners and fuel manufacturers to produce transportation fuels that cost considerably less than today's petroleum-based fuels, while reducing overall emissions, NOx, sulfur and particulate matter. Fuels made with Siluria's processes are also compatible with existing vehicles, pipelines and other infrastructure and can be integrated into global supply chains."
The New York Times reported recently that the number of mobile or "walking" drilling rigs in operation now exceeds the number of conventional rigs, by 650 to 500. "Pad drilling" -- the drilling of multiple wells from a single pad site -- has now become the norm in unconventional plays, and these walking rigs make drilling from a single pad site more economical and efficient. Moving a rig to a new location now takes a matter of hours instead of days. The new rigs cost up to $20 million. The increased effeciency of these rigs has actually reduced the rig count while increasing the number of wells drilled, and has caused the Energy Information Administration to develop a new rig-efficiency measure. The combination of walking rigs and multi-well drillsites results in significant reductions in drilling costs. Continental Resources, the largest player in the Bakken, says it now can drill 14 wells from a single pad.
EIA's new Drilling Productivity Report shows how the new technology has affected production in the major shale plays. Here is its graph for the Eagle Ford:
Here is an annual comparison for several shale plays:
Not necessarily good news for drilling companies, but good news for exploration companies and royalty owners.
From Northern Oil and Gas:
I have recently seen articles predicting the end of the shale boom, coming not only from those who have consistently predicted that shale production would never amount to anything, but also from respected sources whose predictions have previously proven accurate. A recent Houston Chronicle article quotes from a paper written by Amy Myers Jaffe, executive director for energy and sustainability at the University of California, Davis, and Mahmoud El-Gamal of Rice University, saying that "The most likely scenario - absent war - is for oil prices to decline significantly." A significant decline in oil prices would make many if not most wells shale wells now being drilled in the Eagle Ford and Permian areas of Texas uneconomical. Jaffe expects oil prices to decline in the next three to five years. "To hold up prices it would have to be a regime change in several countries that results in lasting civil wars with lots of infrastructure being blown up," she said.
An article in Business Week says that the break-even price for profitability in the Cline Shale play of the Permian Basin is $96 per barrell; in the Eagle Ford, it's $78/barrel, and in the Bakken, $84. Here is one analyst's prediction of future oil prices:
Falling fuel demand is a big part of the prediction. Jaffe believes demand will fall even with continued growth in China and other emerging nations. The average fuel economy for new vehicles in the US is up 4.7 mpg since October 2007. And Americans are driving less. Lower-priced natural gas will replace some of the oil demand. From the Energy Information Administration:
And, as with natural gas in the latter part of the last decade, US crude oil production and resulting supply are increasing:
EIA has begun publishing a new report, its "Drilling Productivity Report," focusing on production in the six major shale plays in the US. The report appears to me to highlight two attributes of shale plays: first, companies are lowering the cost of drilling and completing wells in these plays, increasing the efficiency of putting new production online; and second, the industry has to continue to drill wells to replace the rapid decline in production from these plays. Here are a couple of the EIA's charts from its recent analysis of Eagle Ford wells that illustrate these attributes:
This shows that fewer rigs are needed to continue the increase in production from the Eagle Ford.
On the other hand, it takes continuous drilling to replace the decline in existing production:
The above chart tells me that, if and when oil prices decline, the growth in oil production from the Eagle Ford will quickly turn into a rapid decline, when rigs leave the play.
Some big horizontal wells have begun producing in Zavala County from the Buda formation (below the Eagle Ford) that may open up Zavala County for additional wells comparable to the best Eagle Ford Wells. This Hughes well, now having a history of production for a year, shows no sign of letting up:
Here's another Buda well, completed by Sage Energy:
Here's a well recently completed by Texas American Resources, headquartered right here in Austin:
Good news for those holding acreage in Zavala County.
There has been a lot of discussion lately about the demand on groundwater from its use to hydraulically fracture wells, and possible contamination of wells by hydraulic fracturing and improper completion of wells.
Air Products and Chemicals is promoting the use of nitrogen foam instead of water in fracking in shallower formations.
A second study of wells in the Marcellus Shale led by Rob Jackson of Duke Universty, published in the Prodceedings of the National Academy of Sciences, found increased methane in water wells located close to recent shale wells. "Overall, our data suggest that some homeowners living <1 km from gas wells have drinking water contaminated with stray gases," Jackson's team concluded. The study does not directly link the methane to the Marcellus wells because of the lack of data on the quality of the groundwater before the wells were drilled.
The EPA has abandoned its investigation into possible contamination of groundwater by fracking in Pavillion, Wyoming, saying that it would instead support the state's investigation. EPA released a draft report in 2011 that found frac fluids present in groundwater; its report was heavily criticized by the industry.
Scarcity of groundwater in the Permian Basin in West Texas has caused operators to turn to water recylcing and use of brackish (non-potable) groundwater. A recent study by UT Austin estimated that 20% of the frac water used in that area came from recycled or brackish water. The study found that in Dimmit, Webb and LaSalle Counties - all in the Eagle Ford Shale -- more than 50% of total water use comes from mining, which includes fracking.
Barnhart, a small town in Irion County in West Texas, has run out of water. It's well has run dry. The Texas Commission on Environmental Quality has listed 30 communities statewide that could run out of water by the end of the year.
A report by the Texas Water Development Board showed groundwater levels dropped significantly in Texas aquifers. In South Texas' Carrizo-Wilcox aquifer, the principal source for frac water in the Eagle Ford, median groundwater levels dropped 4.4 feet in monitoring wells, and the average drop was 17.1 feet. One monitoring well in LaSalle County ropped some 136 feet.
Here is a good article on the relation between water resources and hydraulic fracturing:
Ceres, an environmental non-profit, has published a paper analyzing water use in fracking operations and efforts being made by industry to use alternatives to potable groundwater. It found that more than half of the wells drilled in Texas in 2011 were in areas with high or exremely high "water stress."
A recent article in the New York Times highlights the difference between "oil," or "owal" as we say in Texas, and the heavy crude oil mined from Canadian tar sands. A major waste product of that mining is coke. The tarry substance mined in Canada goes through an initial refining process to separate the crude from tarlike bitumen, caled "coking." The tarry solid left from the process is called coke. It can be burned, and is an essential ingredient in making steel. The coke created from Canadian tar sands has a high sulfur content. Some of the Canadian tar sands are now being coked in a refinery in Detroit owned by Marathon Petroleum, and the coke by-product is sold to Koch Carbon, owned by Charles and David Koch. (I'm not making this up.) The Koch brothers have recently been in the news for considering an offer to buy the Los Angeles Times and the Chicago Tribune. They are also famous for supporting conservative and libertarian political causes.
Here is the picture from the NYT article showing the stockpile of coke along the Detroit River belonging to the Kochs:
The crude oil generated by the coking process is the oil that is supposed to go through the Keystone pipeline running from Canada to the Texas coast, if that pipeline ever gets regulatory approval. According to the NYT article, Canada has 79.8 million tons of coke stockpiled. Efforts are underway to export Canadian coke to China and Mexico as a fuel. California, which also produces heavy crude that has to be coked, exports about 128,000 barrels of coke per day, mostly to China. The EPA does not permit it to be burned in the US. The Oxbow Corporation, owned by William I. Koch (a brother of David and Charles), is one of the world's larges dealers in petroleum coke, selling about 11 million tons a year.
Here are some pictures of petroleum mines in Alberta, Canada:
This is what the raw petroleum sand looks like:
A study written by J. David Hughes and published in February by the Post Carbon Institute claims that shale gas reserves are vastly overstated. "Drill Baby Drill - Can Unconventional Fuels Usher In a New Era of Energy Abundance?" A companion article by Deborah Rogers claims that the shale "frenzy" is a Wall-Street-created bubble, that "U.S. shale gas and shale oil reserves have been overestimated by a minimum of 100% and by as much as 400-500% by operators according to actual well production data filed in various states," and that "shale oil wells are following the same steep decline rates and poor recovery efficiency observed in shale gas wells." "Shale and Wall Street: Was the Decline in Natural Gas Prices Orchestrated?" Both are published on a website called shalebubble.org. These nay-sayers are continuing a tradition that has followed the oil and gas industry for decades - the debate between the peak-oil advocates and those who believe we will never run out of fossil fuels.
David Hughes' study is worth reading. He studied more than 60,000 shale wells in the US and their rates of decline, costs and reserves. Hughes concludes that more than 1,542 wells will have to be drilled each year in the Bakken and Eagle Ford plays just to maintain current production, at a cost of $14 billion per year. He estimates that it will take $42 billion and more than 7,000 wells per year to maintain current levels of production of shale gas, whereas the value of the gas produced in 2012 was only $32.5 billion. Some examples from Hughes' study:
On overly optimistic predictions by the Energy Information Administration:
Hughes' decline curve for Eagle Ford wells:
Hughes' prediction of future production from the Eagle Ford and Bakken plays:
And on the world's insatiable appetite for fossil fuels:
Hughes' study is mentioned in "What If We Never Run Out of Oil," by Charles C. Mann, in the May edition of The Atlantic magazine. Mann gives a broad historical perspective to the debate over the ubiquity of fossil fuels. Mann begins by recounting his visit to the Kern River oil field in California many years ago. One of the first and biggest oil fields discovered in the US, Kern River was discovered in 1899. In 1949, after 50 years of production, analysts estimated that 47 million barrels of recoverable reserves remained. In the next 40 years, the field produced 945 million barrels, and in 1989 analysts estimated the field's remaining reserves at 697 million barrels. By 2009, the field had produced more than 1.3 billion barrels and remaining reserves were estimated to be almost 600 million barrels.
Mann then tells the story of M. King Hubbert, a prominent geophysicist at Shell oil in the 1950's. In 1956, Hubbert predicted that crude oil production in the US would peak between 1965 and 1970. In 1964 Hubbert went to work for the US Geological Survey. The head of the USGS at the time, Vincent E. McKelvey, was an optimist about US oil and gas reserves, and his agency issued optimistic assessments of US oil industry's future. McKelvey denigrated Hubbert's pessimistic projections and eventually forced Hubbert to resign from USGS. Although McKelvey derided Hubbert's theories, they proved to be correct, and the decline in US production led to the oil embargo and gas lines of the 1970's. Jimmy Carter adopted Hubbert's views in declaring that the planet's proven oil reserves could be consumed by the end of the next decade. The Carter administration imposed energy-efficiency measures including gas-mileage regulation, home-appliance energy standards, conservation tax credits and subsidies for weatherization.
Mann says that the debate continues today between pessimists and optimists, Hubbertians and McKelveyans, "hammering at each other like Montagues and Capulets." The difference between the Hubbertians and the McKelveyans is in their conception of what is a "reserve." The Hubbertians think of reserves as a physical entity - oil in the ground. The McKelveyans think of reserves as an economic judgment: how much petroleum can be harvested from a given area at an affordable price. In fact, reserve estimates are a mixture of the two - at least if you are wanting to know "recoverable" reserves. What is "recoverable" depends on the price of the commodity and the cost of extracting it. As prices rise, recoverable reserves increase. As technology improves and costs drop, recoverable reserves increase. And vice versa. Because there will always be some oil in the ground that is too expensive to recover at any point in time, McKeleyans say that the world's supply of oil will never be exhausted. Thus the idea behind Mann's article: "Will we ever run out of oil?"
And now the shale boom, and predictions that the US will soon be energy-independent. If the past is any judge, any prediction is sure to be wrong.
Mann's article goes well beyond the peak oil debate. He explores the possibility of commercial production of methane hydrate as the next breakthrough in unconventional hydrocarbon resources. Methane hydrate is gas trapped in frozen water crystals beneath the sea bed.
Mann says that "Estimates of the global supply of methane hydrate range from the equivalent of 100 times more than America's current annual energy consumption to 3 million times more." A core sample of methane hydrate was found to contain 99.4% methane. The ice crystals in which the methane is trapped can be lit afire - burning ice.
Japan has spent $700 million on methane hydrate research over the past decade. Its ship, the Chikyu, is the world's most sophisticated research vessel. It recently tested a method of recovery of methane from methane hydrate that produced about 4 million cubic feet of gas.
Mann speculates on the global geopolitical consequences of a shift to unconventional hydrocarbon resources like shales and methane hydrate. Although it would be a relief not to rely on Middle East reserves for US energy supply, such a shift could have destabilizing results in the economies and politics of nations who even now are in the middle of unsettling developments. Mann quotes Daron Acemoglu, an MIT economist and co-author of Why Nations Fail: "Think of Saudi Arabia. How will the royal family contain both the mullahs and the unemployed youth without a slush fund?"
The US is unique among the 62 petroleum-producing nations in allowing private entities to control most oil and gas resources. In most nations, these assets are owned or controlled by the government. Michael Ross, a UCLA political scientist and author of The Oil Curse: How Petroleum Wealth Shapes the Development of Nations (2012), says that this naturally leads to corruption. Such oil-based economies become unstable when shortfalls in oil revenues eliminate the sole, unsteady support of the ruling elite.
The world has become totally dependent on fossil fuels for its economy and well-being. As Mann says:
[E]conomic growth and energy use have marched in lockstep for generations. Between 1900 and 2000, global energy consumption rose roughly 17-fold, ... while economic output rose 16-fold - as close a link as one may find in the unruly realm of economic affairs.
We depend on hydrocarbons for everything from lighting our homes to providing energy to build our computers to running our cars. Modern life would be impossible without hydrocarbons. Humankind's appetite for energy is insatiable, and is sure to grow as developing countries continue to increase their standard of living. We need to understand and be aware of the consequences. Mann's article is a good place to start.
A recent editorial in the Houston Chronicle makes a good point: we should no longer think of "oil and gas" together. Their paths have diverged, at least in the US.
The prices of oil and gas used to be roughly equivalent, based on their energy value - their Btu content. But since the shale revolution in the US, this is no longer the case. Today, gas is much cheaper than oil on an energy-equivalent basis. Today, most exploration companies have moved from gas shale plays to oil shale plays, chasing the higher oil price. But gas prices have recently risen, and wells are still being drilled profitably in the Marcellus. If gas returns to $5-6/mcf, shale gas plays will return, and gas will still be much cheaper than oil.
Second, gas is a clean-buring fuel, unlike oil or coal. US emissions of greenhouse gases have declined substantially since utilities have gradually switched from coal to gas. Vehicles powered by gas have much lower emissions than those fueled by gasoline. Gas is touted as a "bridge fuel" in the transition from hydrocarbon to renewable sources of energy, because of its lighter environmental footprint.
So why are we still using so much oil? Principally because of the transportation sector. It is expensive to convert vehicles to burn natural gas, and there is a dearth of refueling stations in the US for natural gas. If the price of natural gas remains cheap, more and more vehicles will burn it instead of gasoline.
As the public begins to better understand the differences between oil and natural gas, and as the market's confidence grows in the US supply of gas, the stability of its relatively low price, and its more benign environmental impact, gas should make inroads into the transportation industry.