Recently, across the US, there has an outpouring of hate for fracing. From movies, such as Gasland and Promised Land, to local communities banning tight oil and gas operations, the issue of fracing has become a cornerstone of the environmental movement. There are people claiming that “Big Oil” is out there to pollute the water of America and destroy the earth. Of course, the reality is far from that. It has always been interesting that anything that is “big” in America is automatically considered bad as if the people that work in these companies are inherently trying to do something evil because they work for a successful business someone built. No one I have ever worked with in the oil industry has ever told me that they got into the business of energy production to engage in a Machiavellian scheme to destroy the earth. With that stated, it is important to look at the facts around fracing and to understand what the true risk factors are without all of the hyperbole surrounding it.
Fracing was first developed in the 1940’s as a method to increase the production in oil and gas wells. Over a million wells have been hydraulically fractured worldwide since then. The technique involves pumping water and sand down a wellbore inducing fractures in the reservoir to open up the rock to flow more easily. These fractures are incredibly small with most of them being significantly less than an inch in width. They typically extend upwards up to 300 feet and can extend laterally from between 100 to 2000 ft. The reason why they do not extend upward for very large distance is due to them having to overcome the thousands of feet of rock weighing down creating pressure on the reservoir. Most reservoirs are located at thousands of feet of depth and are not located anywhere near where usable water aquifers are. In fact, using seismic technology, the government and oil companies have monitored numerous fracing jobs and have shown no growth of fractures anywhere near fresh water. In areas across Texas, such as Ft. Worth where hundreds of wells have been drilled in the middle of a city, millions of people have lived for decades next to oil wells with no ill effects. In terms of composition, 99% of frac job fluids are composed of water and sand. The majority of the remaining chemicals are items used daily in many consumer products such as cosmetics, soap, and food. Additionally, there are layers of steel and cement set between the producing zone that isolate and further protect fresh water zones. In conclusion, there are numerous safe guards, historical data, and scientific reasons why fracing is not harmful to anyone’s health, safety, or the environment.
Hydraulic Fracture from Sandia Labs
Breakdown of Frac Fluid Composition (click to enlarge)
Graphic showing fracture height growth and distance to water table (click to enlarge)
Fracing is the reason why today the US is moving to energy independence. As a result of horizontal drilling technology and fracing, the US has seen record growth in production in both oil and natural gas. By replacing coal fired power plants with natural gas, the environment is becoming cleaner due to decreases in emissions. Energy prices have stabilized or dropped as a result of this technology allowing everyone a better quality of living. More jobs are being created in America in a down economy. It seems like a bad idea to ban something that has done so much for the country and that has been proven safe and proven for many years.
Chart showing growth of shale gas in the U.S. (EIA)
The publication of the State Department's latest environmental impact report
on the Keystone XL pipeline project has sparked great interest in the logistics of shipping crude oil by rail. As described in a long article
in the Washington Post, the availability of a rail option for oil sands crude could prove to be a crucial element in determining whether the pending decision to permit the pipeline to cross the US border would actually affect Canada's oil sands output, and thus its greenhouse gas emissions. As the article makes clear, however, oil's rail trend is already well underway , thanks to the surge of "tight oil" production from shale formations. Moving crude oil by train is experiencing a "Back to the Future" moment.
Oil shipments in rail cars are nothing new; the practice dates back to the earliest days of the oil industry. In fact, control of key railroad routes for oil and petroleum products was an important aspect of the US government's anti-trust case
against the original Standard Oil a century ago. My first exposure to crude-by-rail was in the 1980s, when significant quantities of heavy crude from California's San Joaquin valley were routinely transported to Los Angeles refineries by dedicated "unit trains", because there wasn't sufficient pipeline capacity available.
The same dynamic applies today, with the rapid expansion
of tight oil production in North Dakota's Bakken fields quickly outstripping the capacity of the state's few existing pipelines
to transport the oil to market. A tank car loading rack
requires much less time and money to build than a new pipeline or pipeline expansion. US railroads are also eager for the traffic, since coal deliveries, which accounted for 45% of US rail traffic
in 2011, fell by nearly 11% last year as natural gas eroded coal's share of power generation
. Meanwhile oil shipments by rail grew by 46% in 2012.
Precise data on just how much crude oil is currently moving by rail are hard to find. The American Association of Railroads
doesn't differentiate between crude oil and refined petroleum products, which until recently accounted for most oil-related rail shipments. The US Energy Information Agency (EIA) reported
last summer that crude oil had grown to roughly 30% of total petroleum rail deliveries, which would equate to around 300,000 barrels per day (bpd) on average for 2012. Yet EIA's analysis of recent trends suggested that crude-by-rail increased by nearly 250,000 bpd last year alone. The CEO of the Burlington Northern Santa Fe recently indicated
that his railroad's total oil-related shipments alone could expand to around 1 million bpd, roughly double today's
It would be easy to conclude that all this growth reflects a temporary expedient, until the nation's pipeline capacity can be expanded and realigned to match rising output and the reversal of long-standing import trends. That view is clearly not shared by oil companies and traders who are lining up to purchase or lease new tank cars for this service
. Perhaps that's because rail provides a degree of flexibility that would be nearly impossible to match by pipeline. For example, it creates an opportunity to supply domestic crude to East Coast refineries like Delta Airlines' Trainer, Pennsylvania facility
, which had previously become uneconomical to operate on a diet of imported crude cargoes. Similarly, even if a pipeline from North Dakota to the San Francisco Bay Area could be justified economically, it would likely never receive the necessary permits. Yet Valero's Benicia refinery might soon receive up to 70,000 barrels per day of Bakken crude by rail
Railroads are also surprisingly efficient. At an industry average of 480 ton-miles per gallon
, my analysis indicates that shipping a barrel of crude from North Dakota to a refinery in either Houston or Philadelphia consumes a quantity of diesel fuel equivalent to just 1% of the energy content of the oil, while adding slightly over 1% to the typical well-to-wheels emissions
for gasoline refined from it. That's higher than for pipelines, but not by enough to render the option unattractive.
Pipelines remain the preferred option for moving high volumes of oil safely over long distances and, when capacity exists, are usually cheaper for shippers. However, rapidly shifting sources of production and the high capital costs of new pipelines, combined with an increasingly challenging regulatory environment, could provide a durable opportunity for oil-by-rail, just as it has for moving petroleum products and ethanol by train
The spread between the US and international crude markets has grown very wide. West Texas Intermediate crude currently sells at about a $21 per barrel
discount to UK Brent crude--an extraordinary markdown for a grade of oil that was the world standard just a few years ago. In a post last December
I discussed the influence of pipeline bottlenecks, particularly in the middle of the US, on this relationship. This week I read an interview
with an oil investment analyst questioning the notion that relieving those bottlenecks would bring US crude back into alignment with the global market. His argument hinges on the capability of US Gulf Coast refineries to adapt to a diet of lighter, sweeter crude oil, compared to the heavy grades they've been accustomed to running. Although his point serves as a useful reminder of the complexities affecting oil prices, I can't help wondering if it underestimates the flexibility of the US refining system.
I doubt there's a generic answer to the question Mr. Schaefer of the Oil & Gas Investment Bulletin poses. It's not just a matter of whether it might be more profitable for these refineries to process heavy oil and export light, as I've suggested in the past, but if refineries that have been modified for a heavy crude slate can still revert to running the lighter crudes coming out of the Bakken and Eagle Ford shales, which seem broadly similar to those for which many of them were originally designed.
To a large extent that would depend on the specific configuration of each refinery, along with the market it serves. Understanding why requires at least a cursory understanding of how refineries work. If you look at even a simple refinery flow schematic
, you'll notice numerous interconnections between the various process units. Unfinished products flow from one unit to the next until blended finished products come out the other end, but those aren't the only important flows. What makes today's refineries around 90%
efficient is clever recycling of heat and byproducts like hydrogen and fuel gas. In order for the whole facility to operate smoothly, all its units must remain in balance with each other. If you feed the atmospheric distillation column
, or "crude unit" at the front end with very light crude oils that, when distilled into their components, overwhelm some downstream units and starve others, that careful integration will break down.
This seems to be the essence of Mr. Shaefer's point: that the Bakken and Eagle Ford crude streams are too light, yielding abundant LPG, gasoline and diesel but insufficient "gas oil" and residue to keep the fluid cat cracker--the gasoline-making heart of a modern refinery--and other downstream units running properly. For some facilities in some locations that could be an important insight and limitation. Certainly the California refinery where I once worked as a process engineer would have choked on 47 gravity Eagle Ford or 43 gravity North Dakota Sweet
, having been designed for an average API gravity (a measure of crude oil density) of around 20. However, it's worth recalling that no significant new oil refinery
has been built in the US since the 1970s, although many have been upgraded substantially since then. That means that most of today's Gulf Coast refineries have cores that were built at a time when domestic light sweet crude was still abundant.
Refinery engineers and the supply departments that work with them can also be quite resourceful. I recall that when I was a trader for Texaco's US West Coast operations in the 1980s, we routinely purchased intermediate feedstocks from other refiners, to keep our refineries' cat crackers and cokers running during crude unit maintenance or when their current crude slates didn't naturally provide enough. Between shifts in the mix of other crude oils run in conjunction with light oil, and supplementing with feedstock purchases, Gulf Coast refiners might have more flexibility to maximize purchases of shale oil, or "tight oil" than Mr. Shaefer's argument credits.
Ultimately this issue factors into a larger debate concerning how to extract the greatest benefit from the new oil bounty that shale production techniques are providing. Are we better off with constrained pipelines that force some producers to discount their output so it can still reach market by rail or truck, and incidentally provide some refineries with a cheap source of crude? Does the maximum advantage accrue from ensuring that all US crude production is processed in US refineries, even if they increasingly export
their products internationally, in light of weak US demand? Or should we suspend outdated crude oil export restrictions and allow both producers and refiners to compete in the same global market that already sets most US refined product prices? That's a worthwhile debate, and I'd be surprised if it were settled based on the physical constraints of the sophisticated refineries of the US Gulf Coast.
Oil exploration used to be a high risk and high reward industry. Investing millions of dollars in projects that had a possibility of absolutely no return (the infamous “dry hole”) required a gamblers mentality that to a large degree is no longer present in the onshore US oil and gas business anymore. As the number of colorful wildcatters has declined, the oil industry has become more institutionalized. The reason this has occurred in a large part is due to the change in how the industry quantifies or views risk.
When developing an onshore project, there are 3 main reserve considerations that management reviews before approving any well. The three risk factors are Pg, Pm, and possible recoverable reserves. Pg is the chance that you will locate a reservoir with hydrocarbons present in it. This number in the past could vary widely even sometimes going as low as 20%. Of course, if you were drilling wells with such high chances of failure, you needed to have a large possible recoverable reserve value allowing you to hit a “gangbusters well” with huge amounts of oil and gas in it. Generally, these types of high risk and reward wells would be drilled in multiple well packages to allow you to have a managed portfolio risk. Although, often times, someone would come up with a unique target drilling program and sell it to a group of oil and gas investors and “prospect” it out. This type of investment appealed to a large number of high net worth individuals since essentially you were engaging in a treasure hunt 1 to 4 miles under the earth. The final risk factor is Pm which is the risk of not having a mechanical failure (drilling a well which has a producible pathway for the hydrocarbons). There is always a risk of mechanical failure in any oil and gas operation due to the complexities of targeting reservoirs at high temperatures, pressures, and depths. This risk was especially true when you were drilling a well in a new area you have never done before (the” true wildcat”).
Nowadays, the game has changed. With the development of resource plays (see my first
post) , Pg has become almost 100%. Statistically, it is almost impossible to have a dry hole in a resource play since you know the oil and gas is always going to be there. The Pm factor is also 90% or even greater. Due to the repeatability of resource plays, the drilling & completion program has to manage with less risk and has transferable knowledge to be improved upon from previously drilled wells. The one downside of resource plays is that the wells don’t necessarily produce as much as wells drilled in the past. However, there is a level of consistency present which results in more stable profitability and returns. Most importantly, operators are able to optimize reducing drilling and completion costs over time of individual wells and increasing reserves as they learn what factors are important in each reservoir. Operators are able to deploy large multi-billion dollar capital programs and numerous rigs on a scale that was not possible in the past due to the repeatability of these resources. The effect of this can be seen in the large increase in natural gas and oil production the US has been experiencing over the last few years (as discussed by Geoffrey Styles,
in the previous post
In conclusion, although the elephant hunt of the past might be over in the US, the advent of resource plays has guaranteed the US a long and stable supply of energy. It makes for a little bit less of excitement, but when your money is involved that is probably for the best.
In my last posting
I concluded that the energy transformation fueled by hydrocarbons derived from shale deserved to be called a revolution. In many ways, we are still on the threshold of that revolution, both in terms of the full implications of expanding shale gas supplies and of the application of similar techniques to unlock large resources of oil and other liquid hydrocarbons. Just as shale gas reversed the decline of US natural gas production, this shale oil--often called "tight oil" and distinct from oil shale--is now reversing a long-standing decline trend
in US oil production, despite the slowdown in deepwater production
from the Gulf of Mexico following the Deepwater Horizon accident. If these trends continue at recent rates, they could dramatically alter the energy relationships between North America and the rest of the world.
Due largely to the contribution of liquids-focused shale developments such as the Bakken shale in North Dakota, the Eagle Ford in Texas, and the Niobara in Colorado, Kansas, Nebraska and Wyoming, US oil production increased by 6%
between 2009-11, with output this year averaging 6.2 million barrels per day
(MBD) through May. That is more than 25% above the 2008 low point for US field production. Together with reduced demand from the weak economy and improved energy efficiency, shale oil has helped reduce US oil imports from 60% of total supply
in 2005-6 to 46% last year. In its latest forecast the US Energy Information Agency (EIA) projects that these trends would drive net oil imports down to just 36% of supply
by 2035, even with oil production only growing to 6.7 MBD
in 2020 before declining again. Yet that production forecast looks conservative compared to others, including a recent forecast from Citigroup
, which suggested that US liquids output--including natural gas liquids but excluding biofuels--could grow from 8 MBD in 2011 to 14 MBD by 2020, based on shale development and expanded deepwater production.
Many uncertainties govern global oil markets, including significant uncertainties about the future pace of US and international shale oil development, so the ultimate effect of these new supplies on future oil prices is unknown. Still, they seem consistent with a lower oil-price future than would have been credible just a few years ago, while indicating that the expected shift in market power and geopolitical influence toward OPEC and away from major consuming countries such as the US and China could be postponed or at least diluted for years to come. That would have profound consequences for the US and global economies and for the geopolitics of energy.
Meanwhile, shale gas has not yet reached its maximum output in the US and is still in its infancy elsewhere. The EIA forecasts
a further 22% growth in total US gas production from 2011 levels by 2035. Production would exceed domestic demand by 2022, despite further inroads by gas in power generation to provide 28% of electricity
, largely at the expense of coal. Shale output is expected to account for roughly half
of US natural gas production by 2035. Even after compensating for declining US conventional gas output, this should be sufficient to jump-start new gas demand sectors, including in transportation and for exports of liquefied natural gas (LNG).
The US is expected to become a consistent LNG exporter
even before the point of net exports is reached, for two reasons. US gas will be available for export before then, because significant quantities of Canadian gas are likely to continue flowing to the US due to infrastructure and other logistical factors. At the same time, the wide gap between international LNG prices, often linked to oil prices, and most domestic gas markets provides an economic incentive for exports. This switch from LNG imports to exports is already reshaping international LNG markets. Nor is this the only important shift, globally. In its "Golden Age of Gas" report in 2011, the International Energy Agency proposed
that global gas production could grow by more than 50% over 2010 levels by 2035, with the share of unconventional gas "rising from 12% in 2008 to nearly 25% in 2035."
Not long ago, US oil and gas production appeared to be in a permanent state of decline, leading to serious concerns about growing import dependence for both. Many regarded renewable energy sources such as wind, solar and geothermal energy and biofuels as the only solution, even though it was clear to most experts that it would take decades for them to reach the necessary scale. Yet in just a few years shale development has emerged to provide a robust bridge between declining conventional hydrocarbons and expanding renewables, if not a new base supply altogether. The resulting reduction in energy dependence might not entirely insulate the US from future oil price spikes, but it will mitigate their impact on US trade and fiscal deficits. Other implications of the shale revolution are just beginning to be felt, both in the US and globally.