The International Energy Agency (IEA) released
its latest World Energy Outlook
(WEO) on November 12th, looking twenty-plus years into our energy future. The trends it describes add nuance and detail to last year's projections
, rather than upending them. Among other things they advance the expected date of global oil production leadership by the US to 2015 but suggest these gains may be short-lived and will not lead to "cheap oil." The IEA also envisions a reshuffling of the traditional roles of energy importing, exporting and consuming countries, against a backdrop of steadily increasing energy-related greenhouse gas emissions.
As in previous years, the new WEO examines the full range of energy supply and demand, with a focus this time on the sources and uses of petroleum, and the emergence of Brazil as an oil and energy power. While recognizing
that they might be underestimating the potential for technology or additional resource discoveries to sustain the growth of "light tight oil", or shale oil, which together with oil sands and gas liquids is a primary driver of oil supply growth today, the IEA forecasts it would peak by 2025.
That puts the burden for supporting oil demand growth and the replacement of supplies lost to natural decline after 2025 back onto the Middle East producers. So in the IEA's view, OPEC's loss of market power appears temporary. A corollary to this is that the agency does not anticipate a sustained drop in oil prices, but rather a gradual increase of about 16% by 2035
. That's because the unconventional oil helping to drive current market shifts is still relatively high-cost, compared to the large conventional oil resources of the Middle East.
Although the IEA expects the global oil market to grow from its present level of around 90 million barrels per day (MBD) to 101 MBD in 2035, that change would be less than their forecasted equivalent global growth in gas, renewables or even coal. The concentration of oil demand in transport and petrochemicals would also increase, while other uses contract slightly. This is consistent with last year's observation that the center of the oil market is shifting towards Asia, since around one-third of the total anticipated growth in oil demand is for diesel to fuel goods deliveries in Asia.
The shift toward Asia applies to other forms of energy, as well, including natural gas and the expanded use of renewable energy. This trend is already altering global energy trading patterns, and with the US becoming more energy self-sufficient the IEA sees a new role for energy exports from Canada to supply Asia. That includes both LNG and oil sands, which Fatih Birol, the IEA's chief economist, recently indicated the agency sees as only a minor, incremental
threat to the climate compared to growing coal use.
An added nuance in this year's outlook is that the IEA now expects world-leading energy growth in China to be overtaken in a decade or so by faster growth in India, while rapidly growing consumption in the Middle East could result in that region posting the second-highest growth in primary energy demand through 2035, especially for natural gas.
In the launch presentation
in London Dr. Birol assessed the consequences of strong North American energy growth and shifting exports and imports for the prices that industries pay for energy. Because any exports of low-cost North American shale gas must be priced to cover the cost of liquefaction and long-haul freight, plus a margin, global natural gas prices should converge somewhat but still not equalize among the major consuming regions. As a result, the IEA expects US-based energy-intensive industries to have a persistent cost advantage in both gas and electricity, enabling them to increase their share of global markets. That has implications for employment and economic growth, while sustained energy price disparities should also drive energy efficiency improvements in response.
Another issue that received prominent attention at the launch was the always controversial matter of subsidies, for both conventional and renewable energy. The IEA estimated global fossil fuel subsidies at $544 billion 2012--mainly in developing countries and Middle East oil producers--resulting in "wasteful consumption
" and fewer benefits for the poor than commonly claimed. And while supporting the use of subsidies to promote greater use of renewable energy, the agency's Executive Director, Maria van der Hoeven, made a particular point about the necessity for such subsidies to be carefully targeted and very responsive to changes in technology cost.
The IEA was founded in the aftermath of the 1973-74 Arab Oil Embargo and will celebrate its 40th anniversary next year. I couldn't help thinking about that as I reviewed the updated WTO materials. They're interesting as an annual update, but also in reflecting how the world of energy has changed since the oil shocks of the 1970s.
The rapid development of unconventional oil and gas that underpins the IEA's latest forecast would likely have amazed the industry veterans I met at the start of my career, but still fit within their worldview. I think they would have found the projected growth of renewable energy, supported by climate-change-inspired subsidies that surpassed $100 billion per year in 2012 more futuristic and surprising. Yet despite the anticipated expansion of renewable energy sources over the next 22 years, the share of fossil fuels in the world's total energy supply only falls from 82% today to 76% in the IEA's main "New Policies" scenario. That might seem overly cautious, but it underlines the challenges involved in changing such massive systems.
Natural gas prices have been in a slump in the US for several years now with prospects for returning to 2008 pricing of $8 for dry gas looking somewhat dim. Most companies that have been drilling gas wells recently have been producing reservoirs with high natural gas liquid and condensate yields which increase the effective gas price. However, there is a new breed of dry gas driller out there and they are drilling for a gas you would never expect.
Most people think of this gas only when they are having a birthday party but helium prices have risen to over $160 per MCF (over 40X the price of methane). As it turns out, helium’s main use is not balloons but for medical, cryogenic, pressurizing, purging, and welding applications. Having a low density, boiling point, high thermal conductivity, and being a noble gas (no one wants to have another Hindenburg), helium is used for many applications that no other gas would be as equally suitable. Unfortunately, reservoirs of pure helium do not exist and it is mainly present as a minor quantity in most fields. In certain areas of the country, you find larger quantities of helium making up just a few percent of the total natural gas stream.
Exacerbating the current helium problem is that the US government stored the nation’s supply of helium for decades buying it off the open market (Helium Act of 1960). Then in 1996, the government decided to begin unloading its entire supply of helium (one of the world’s largest repositories of helium) flooding the market selling it at artificially low prices encouraging waste and disposing of the nation’s only major supply of this precious resource. Given that there are no other large readily available sources of helium the market responded over the following decade with prices increasing exponentially as use of helium increased.
One of the reasons why helium is difficult to locate is how it is created.
Helium is typically present in areas with rich radioactive deposits of uranium and thorium present in basement rock (typically igneous or metamorphic). As the radioactive elements decay, they create helium as a byproduct. The light molecule then travels up through fractures and faults and then hopefully ends up in a sedimentary rock reservoir with a trap usually in combination with natural gases such as methane and nitrogen. Once it is produced on surface, it then requires expensive separation techniques to purify it from the rest of the gases it came up with. Finally, it needs to be transported. Most pipelines will not allow a large amount of non-hydrocarbon bearing gases into them.
Thankfully, it appears creative oilmen are slowly coming to the rescue before we reach a crisis level. Although almost none of us have ever considered drilling for helium as an objective, there appears to be a small movement forming of gas drillers who want to start exploring for it. Some companies are targeting states and reservoirs that typically would not be hugely of interest for traditional oil and gas formations but would be possibly prospective for helium. As the price continues to increase, it is even possible that larger companies will get involved in helium exploration and production. Helium is one of the few gases light enough to escape earth’s gravity and be lost forever. As a true resource that cannot be replaced, we need to use it sparingly. With a little bit of luck, we still will be able to have birthday party balloons fifty years from now as long as the oil industry can be successful in its new exploration frontier.
BLM Crude Helium Price and Refined (Grade A) Price Estimates, Fiscal years 2000 through 2012
USGS Chart of Helium use
A recent article
in the Wall St. Journal on the impact of a Midwest propane shortage on farmers trying to dry their corn harvest caught my attention. How could propane be in short supply, when US production is soaring? While it turns out that the shortfall in question is localized and temporary
, it prompted me to take a closer look at LPG supply and demand than I have in many years. I found yet another market that is being transformed by the shale gas revolution.
Like most Americans--except for those in the roughly 5%
of US homes heated with it-- I normally think about LPG only when I have to change the tank on my barbecue grill. That wasn't always the case; early in my career I traded LPGs for Texaco's west coast refining system. I'm happy to see that some of my former colleagues from that period are still involved and frequently quoted as experts on it. Although the LPG market is obscure to many, it represents a microcosm of the issues of reindustrialization and product exports arising from the recent turnaround in US energy output trends.
In order to follow these developments, we first need to differentiate among some confusingly similar acronyms, starting with LPG. Although often used synonymously with propane, it actually stands for "liquefied petroleum gas" and covers mainly propane and butane, though some include ethane in this category. The term reflects the oil refinery source of much of their supply, both historically and to an important extent today. LPG overlaps with natural gas liquid (NGL)--ethane, propane, butane, isobutane and "natural gasoline"-- that has been separated from "wet" ( liquids-rich) natural gas during processing. NGLs are entirely distinct from the anagrammatical LNG, or liquefied natural gas, which consists mainly of methane that has been chilled until it becomes a liquid. By contrast, NGLs and LPG are typically stored at or near ambient temperature but under pressure to keep them in the liquid state.
LPG and NGLs make up a distinct segment of US and global energy markets, falling between the markets for natural gas and refined petroleum products. They are also linked to these larger markets, both logistically and economically. For example, gas marketers vary the amount of liquids they leave in "dry gas" to meet pipeline natural gas specifications
based on price and other factors, and oil refiners blend varying quantities of butane into gasoline, depending on seasonal requirements. Propane and butane are mainly used as fuels, while ethane and isobutane are chiefly chemical feedstocks.
The development of shale gas in the US and Canada has affected the supply of NGLs and LPG in several important ways. First, starting around 2007 increasing shale gas output
helped to halt and then reverse the decline in US natural gas production
from which US NGLs are sourced. Then, following the financial crisis, diverging natural gas and crude oil/liquids prices pushed shale drillers toward the liquids-rich portions of shale basins like the Eagle Ford in Texas, in order to maximize their revenue. The resulting surge of US NGL production
in late 2009 reinforced the decline of US LPG imports
that began with the recession. According to US Energy Information Administration data
, the US became a fairly consistent net exporter of LPG in 2011.
The current US LPG surplus is around 100,000 bbl/day, out of total production of around 2.7 million bbl/day
. That surplus and its expected growth provides the basis for a number of announced
LPG export projects
, as well as the anticipated development of new domestic chemical facilities such as ethylene crackers
that would consume substantial portions of new supply, particularly of ethane.
The success of those projects depends on significant investments in new infrastructure, including gas processing, NGL fractionators to split the raw NGL into its components, and pipelines to deliver NGL to fractionators and LPG to markets. This is particularly true for the Marcellus and Utica shale gas
in the Northeast, from which little or no ethane has been extracted due to limited local demand. Not only is that a missed manufacturing opportunity, but it constitutes a potential constraint on further liquids-rich gas development, since leaving too much ethane in the marketed gas would cause it to exceed pipeline BTU specifications.
In the meantime we're left with a situation that's analogous to the growth of tight oil production from the Bakken shale. New sources of production have come on-stream faster than the infrastructure necessary to deliver them efficiently to where they can be processed or consumed. That puts a growing US surplus of propane and other NGLs in tension with tight regional markets in the Midwest and Northeast, where residential propane prices are running ahead of last year's
at this time. The resolution of this apparent paradox will depend on which infrastructure and demand projects are eventually completed, and how soon.
Self-driving cars, also referred to as autonomous cars, have been in the news for several years. Interest in them
spiked spiked in September 2012, when Google announced
it would make the technology available to the public within five years. Yet while this could be revolutionary in many ways, the most relevant question here concerns their potential to reduce transportation energy demand. At this point the likely effects of self-driving cars on fuel consumption and fuel choice appear less spectacular and more uncertain than their other selling points.
Although the entire concept of a self-driving car might seem science-fictional, it shouldn't greatly surprise anyone who has reflected on the implications of drone aircraft, GPS, smartphones, and the increasing electronification of average cars for the last several decades. From that perspective, the most important constraints on their emergence probably depend less on technology than on social and regulatory factors
The development of self-driving cars and their precursors has been embraced by some of the biggest names in the global automotive industry, including GM, Toyota
, Audi, BMW, Volvo, and Nissan, which recently announced plans
to make the technology available across its entire product line sometime in the next decade. Suppliers to the OEMs are also making important contributions. I vividly recall driving a car equipped with radar adaptive-cruise control and other then-cutting-edge safety features in city traffic at the 2009 D.C. Auto show, courtesy of Robert Bosch, LLC
. All I had to do was tap the gas pedal to engage the system and then steer, while the car did the rest. Systems like this are already appearing in production models.
The two main ways in which self-driving cars could affect future transportation energy usage involve making the operation of vehicles more efficient and enabling bigger changes in vehicle design than would otherwise be feasible. Some of these benefits would start to accrue from the day the first autonomous car left a dealership, but most would require either a critical mass of such cars in the fleet, or overwhelming dominance of the fleet. That could happen sooner in fast-growing developing countries, where legacy fleets are smaller, than in the developed world.
Consider operational changes first. Highway fuel economy could be improved by 20% by means of "drafting"--one car using the car ahead to reduce wind resistance--in automated , self-organized "platoons" of multiple cars
. This, together with the avoidance of collisions, would also reduce traffic congestion, variously estimated
at costing up to 2.9 billion gallons
of fuel each year in the US, or up to 2% of US gasoline demand. The combined potential of these savings, assuming 100% market penetration of autonomous cars, might reach 10 billion gallons per year, a quantity larger than the gasoline displaced by corn ethanol in the US. Of course achieving such savings depends on having large numbers of self-driving cars on the road; imagine the risks if a daring driver in a conventional car attempted to join a platoon of autonomous cars.
The efficiency gains from unattended autonomous parking don't require critical mass, and they might be significant, especially in congested urban areas, where one study
suggested parking consumes up to 40% of gasoline used. However, most of the potential fuel savings could be achieved through simpler and more easily implemented means, such as parking-space sensors and smartphone apps. And while self-driving cars might make car-sharing more popular
, fewer vehicles wouldn't automatically translate into less fuel consumption if the same or more miles are driven.
The second major category of energy savings is associated with structural changes made possible by self-driving cars, mainly resulting in smaller and lighter vehicles. If cars no longer collided with each other or with inanimate objects, they wouldn't need to be nearly as robust. Saving weight saves lots of fuel. Yet it's hard to see how this process could begin before autonomous cars reached nearly 100% market penetration, since for many years they must share the road with millions of cars driven by fallible humans.
Nor is it obvious that self-driving cars would be infallible. We've already seen ordinary models exhibit random self-starting
, due to malfunctioning of remote starter systems that would make up just one small subsystem of an extraordinarily complex self-driving architecture.
Some have suggested that the downsizing and weight savings facilitated by autonomous cars would hasten the adoption of battery-electric cars. The cost of today's EVs is driven largely by battery size, which is in turn a function of the vehicle's weight and its desired performance. A smaller, lighter car could make do with a smaller, cheaper battery pack. Cheaper EVs might well sell faster. However, if that must wait until enough self-driving cars are on the road for downsizing and radical lightening to be safe, it's a reasonable bet that improvements in battery technology in the intervening decades will have bypassed this potential benefit.
In the interim, while there might be some less-significant synergies between EVs and autonomous vehicles, neither technology is likely to depend on the other for its attraction to potential buyers. Nor do I see any obvious benefits for helping alternative fuels like CNG, LNG or biofuels to gain market share.
On balance, if the average medium-term unique fuel savings of self-driving cars are limited to the 10-15% that I calculate--impressive but not game-changing--then the opportunities to improve safety and driver productivity seem like much more important motivators for this technology, for now. And with much skepticism
about the timing of fully autonomous cars that would be widely acceptable to both consumers and regulators, there's a good chance that today's energy concerns will look quaint before such cars arrive in sufficient numbers to have a meaningful impact on them.
Shutdowns of the US government aren't as rare as you might guess. Although the previous one occurred in 1996, it was the 17th since 1976
and the longest. While I don't recall energy being much of a concern during that one, the federal government's involvement in energy has grown significantly since then, particularly in energy regulation and industrial policy, if not so much in terms of R&D spending
. With the current shutdown complicated by the looming "debt ceiling", it's worth thinking about the effects of this situation on energy, and what might lie in store if it isn't resolved soon.
The good news is that the shutdown is unlikely to have a noticeable impact on energy supplies. The provision of energy in the US is mainly done by the private sector, and where federal agencies like the Bonneville Power Authority are involved in producing or distributing energy, they have not been affected so far. In fact, the US is in the midst of a historic boom in energy supplies, especially for oil and natural gas, even though less than half of the public
appears to be aware of this fact. Permitting of new oil and gas drilling on federal lands will be delayed by the shutdown, but most new production is coming from state and private lands
requiring no federal permits.
The shutdown could pose bigger concerns for producers of renewable energy, particularly for projects awaiting approval from federal agencies or payments related to federal renewable energy incentives. While the impact on individual companies might be significant, the impact on overall US energy supplies wouldn't be. One way to gauge this is that the US renewable energy capacity added last year contributes under 1%
of US electricity generation
If US energy supplies are unlikely to be affected much, at least in the near term, what about demand? After all, the federal budget represents just under 23%
of US gross domestic product, and federal workers make up 2% of US nonfarm employees
. A slowdown in government spending puts less money in the hands of consumers. Energy might not be the first thing they'd cut back on, but it would ultimately bear part of any economic contraction
. It's helpful that the current shutdown is partial, affecting around 18% of federal spending based on figures reported by CBS News last week. Still, hundreds of thousands of furloughed federal workers and federal contractors are presumably driving less or using less public transportation. Ridership on the DC Metro system is reportedly way
down. If sustained, this might eventually weaken energy prices, which are already seasonally soft.
However, while energy supply and demand look fairly safe for now, that doesn't mean that a protracted shutdown of the US government would be inconsequential for energy. I've seen several lists of other, mainly longer-term consequences, such as this one
from Denise Bode, former head of the main US wind energy trade association, and another
from Matthew Stepp of the Information Technology and Innovation Foundation. I'd be less concerned about temporary delays in specific research projects at the agencies they mention-- frustrating as those must be to those involved--than the longer-term uncertainties this episode could create, both for recruitment of researchers and the engagement of industry partners necessary to leverage many of these efforts.
A more immediate indirect concern stems from the possible disruption of industry supply chains by trade bottlenecks that are beginning to appear
, due to the absence of various government inspectors and other officials. Delayed imports of pesticide might not affect many energy projects, but delayed steel imports could. If substantial backlogs develop, they could persist after the shutdown ended.
There's also uncertainty about how much longer the Energy Information Administration of the Department of Energy can continue reporting data on energy production, consumption and inventories used by energy traders, investors and analysts. The DOE's published shutdown plan
refers to "a lapse of appropriations" (the trigger for the shutdown) and "the exhaustion of available balances" from prior funding cycles. According to some reports
, that could happen this Friday.
The bottom line is that although it a government shutdown is hardly unprecedented, the world was significantly different the last time we had one. Commerce and supply chains are more globalized, and commodity trading occurs at larger scale and higher speeds, with participation from many more non-industry investors. That's true for energy and many other things.
When it comes to uncharted territory, failing to extend the debt ceiling looks much worse
than the shutdown. Until I started digging into the details, I assumed that in the worst case, Treasury could--despite protestations to the contrary--prioritize payments, keep the US's creditors whole, and avoid defaulting on outstanding debt--though clearly not on other promises. That seems unlikely
Start with the fact that the government actually reached its official borrowing limit in May
, and that since then Treasury officials have been using "extraordinary measures" to reshuffle cash to avoid a default. October 17th is when the Treasury expects to exhaust its post-debt-limit tricks. Even if payment prioritization
were possible, the sudden curtailment of deficit spending would quickly start to affect the parts of the economy that had been protected from the direct impact of the shutdown.
In energy terms, the results might resemble the immediate aftermath of the 2008 financial crisis, when demand for petroleum products and electricity contracted sharply and prices plummeted. Oil bottomed out at $35
a few months later, and natural gas eventually lost half its pre-crisis value of $7.37 per million BTUs
. The last thing we should want to do is repeat that experience and put the tremendous gains in domestic energy production we've made since then at risk.
Because I would be much happier not putting the competing debt limit scenarios to the test, I'm encouraged that there now appears to be movement towards a short-term extension
. Even a few weeks would forestall the worst risks for energy and the economy, while providing sufficient opportunity to resolve the shutdown and begin to address the long-term spending and borrowing trends that helped make the current situation so perilous.
Since the late 1990s natural gas has been identified by both energy experts and environmentalists as a likely "bridge fuel" to facilitate the transition to cleaner energy sources. This view has recently been challenged by suggestions that methane leakage from natural gas systems--particularly from shale gas development--might be significant enough to negate the downstream climate benefits of switching to natural gas. The results of a new study
from the University of Texas, sponsored by the Environmental Defense Fund (EDF) and nine energy companies, should alleviate many of those concerns.
In order to understand why indications of potential natural gas leakage rates well above the previously assumed level of around 1% would cast doubt on the environmental benefits of gas, a brief primer on greenhouse gases (GHGs) is necessary. When present in the atmosphere, these gases contribute to global warming by trapping infrared radiation that would otherwise be emitted to space. Carbon dioxide is the primary GHG implicated in climate change. It currently makes up roughly 400 parts per million
(ppm)--equivalent to 0.04%--of earth's atmosphere and is increasing by around 2 ppm per year
The main constituent of natural gas is methane. Although atmospheric concentrations of methane are much lower than that of CO2, totaling less than 2 ppm
, pound for pound it is a much stronger GHG. Its "global warming potential" is 25 times higher
than CO2's over a 100-year time horizon, and even higher on a shorter time span. While most atmospheric methane has been traced to natural or agricultural sources
, a large increase in atmospheric methane from natural gas production could overwhelm the undisputed downstream emissions benefits of gas in electricity generation, compared to coal.
Several academic studies raised precisely this concern with regard to natural gas produced from shale by hydraulic fracturing, or "fracking", starting with a widely-publicized paper
from a professor at Cornell University in 2010. This work relied on estimates and limited data from early shale production to arrive at a conclusion that shale gas wells leak 3.6-7.9% of their cumulative output. A more recent series of studies
from the National Oceanic and Atmospheric Administration (NOAA) and the University of Colorado Boulder used airborne remote sensing
techniques to calculate leakage rates similar to Professor Howarth's.
Other studies from groups as diverse as IHS CERA
, Carnegie Mellon University
, and Worldwatch Institute and Deutsche Bank
addressed the same question but arrived at much lower leakage rates and impacts. And earlier this year the US Environmental Protection Agency reduced its previous estimate of overall natural gas leakage to a figure equivalent to 1.7%
However, until now all scientific studies of this issue--on both sides--were based on limited data, or on indirect measurements obtained at a significant distance from actual production sites. They relied heavily on assumptions about what was happening at large numbers of gas wells, in the absence of direct observations at these sites.
That's what makes the UT study
so significant; it is based on a wealth of data from actual, on-site measurements at "190 production sites throughout the US, with access provide by nine participating energy companies
." That translates to roughly 500 shale gas wells in different stages of development and production.
Overall, for the segment of the gas lifecycle they investigated, the UT team found methane emissions that were lower than EPA's latest estimates. Emissions from "completion flowbacks" were 98% lower, partially offset by somewhat higher observed leaks from valves and other equipment. Although this study did not measure emissions from the entire gas lifecycle, including pipelines, it would be very hard to reconcile their observed average leakage rate of 0.4% of gross gas production with leakage estimates as high as those embraced by many of shale's critics.
Immediate criticisms of this study
also missed several crucial points. First, without the industry involvement that they characterized as a "fatal flaw", access on this scale for direct measurements at production sites--surely the gold standard for emissions studies compared to estimates based on assumption-laden models--would have been difficult or impossible to obtain. More importantly, they also ignored the fact that the principal sources of methane emissions found by the UT team involved valves and equipment by no means unique to shale development, many of which should be amenable to hardware improvements or different technology choices.
While the UT team and their sponsors at EDF
stated clearly that more work needs to be done to measure methane emissions from other parts of the gas value chain, the current paper convincingly dispels the notion that the emissions from shale gas development are inherently much higher than those for gas produced from vertical wells in conventional oil and gas reservoirs. Since shale gas already accounts for over a third of US natural gas production and is widely expected to dominate future production, that result has large implications for the environmental benefits of further fuel switching and other applications for natural gas.
The other day I saw this headline: "US oil production reaches highest level in 24 years
." Such news isn't as attention-grabbing as it was when this streak began more than a year ago
, once shale oil production ramped up dramatically. What occurred to me this time, however, was how different the current distribution of US oil output is than it was in 1989.
A handful of states still account for the lion's share of US oil production
. Then and now, Texas tops the list, exceeding its 1989 output by 37%. At nearly 2.6 million barrels per day
(MBD) in the most recent reported month --140% above at its low point in 2007--its share of US oil production had grown to around 35% by June. However, beneath Texas the list of top oil states has been jumbled in ways few would have anticipated two decades ago.
Alaska, California and Louisiana, the second-, third- and fourth-ranked producers in 1989, then supplied 41% of total US crude oil output. After decades of decline, the same three states now contribute just 17%, excluding production from the federal waters off Louisiana's coast.
Meanwhile, thanks to the development of the Bakken shale, North Dakota has jumped from the number 6 spot just five years ago to number two, eclipsing Alaska early in 2012. Traditional mid-tier producers like Colorado, Oklahoma and New Mexico are also contributing to the overall US oil revival. This surge of highly productive drilling in roughly the middle third of the country, on top of a million-plus barrels per day from the Gulf of Mexico --mainly from deepwater rigs--has scrambled existing oil transportation arrangements.
When onshore production in Texas and the rest of the mid-Continent shrank in the 1990s and 2000s, the region's pipeline network gradually evolved into the country's principal oil-import conduit. The growth of production in the federal waters of the Gulf of Mexico, which had reached 1.6 MBD at the time of the Deepwater Horizon accident in 2010 but subsequently declined to about 1.2 MBD, meshed well with that model.
Today's big challenge goes against that grain: moving the growing surplus of oil in the upper plains states to markets on the West, Gulf and East Coasts, increasingly by rail
. Much of the turbulence we've seen in the US oil market in the last two years reflects the delays inherent in realigning and expanding that network to accommodate newly abundant domestic supplies.
Yet on the other side of the Rockies, the picture looks very different. When I was trading crude oil for Texaco's west coast refining system in the late 1980s, balancing the crude oil surplus on the Pacific coast required shipping multiple tankers a month of Alaskan North Slope oil to the Gulf, where production was shrinking, and prompted the construction of a new pipeline to send surplus oil to east Texas over land. After two decades of decline from mature fields, along with moratoria on tapping new offshore fields, imports
now make up roughly half of west coast refinery supply
, even though regional petroleum demand is essentially back to 1989 levels
. It remains unclear whether and when
California will allow producers to tap the state's potentially game-changing oil resources in the Monterey shale deposit.
Barring further change, the regional nature of these shifts means that the energy security benefits accompanying the revival of US oil production are a party to which the West Coast has not been invited, or has perhaps declined the invitation. That's significant, because it leaves residents of California, Oregon, Nevada and Washington much more exposed to any disruptions in global oil trade, since the existing US Strategic Petroleum Reserve
was never intended to provide coverage west of the Rockies. In this light, the appetite of west coast refiners for trainloads of Bakken and Eagle Ford crude
looks strategic, rather than just a temporary response to market conditions.
To someone living in 1974, during the first energy crisis of the last 40 years, the idea of mass protests to block a pipeline for importing crude oil from Canada would have seemed incomprehensible. Our environmental awareness has expanded in the interim, along with new channels for exchanging information, including "enduring misconceptions
". Yet the current opposition to so many different energy projects--natural gas drilling, long-distance transmission lines and even wind farms--can also be viewed as an unintended consequence of recent energy successes on a broad front.
The alleviation of what seemed to many a permanent energy crisis might not be obvious, because it has crept up on us. But consider a few of the big-picture elements that have changed:
In crisis mode, US energy security was focused on steadily rising oil and later natural gas imports, while "energy independence" was a goal embraced by politicians but rarely energy experts. Cars offering better fuel economy were available but entailed trade-offs in size and performance. Today, oil imports
are falling, the US is a net exporter
of refined petroleum products, and public concern about Peak Oil is waning, as measured by internet search activity
. The big question
for the federal government this summer is how many natural gas export
facilities to allow. Meanwhile, the threshold for fuel-efficient cars has shifted from 30 mpg to 40 mpg
, offered in numerous attractive models.
Another way to gauge the success of technologies like hydraulic fracturing, or "fracking", in shifting our energy landscape is to remind ourselves how bad we thought today's situation would be, just a few years ago. In 2005 the official US annual energy forecast projected oil imports to increase from 11 million barrels per day (MBD) in 2003 to nearly 15 MBD by this year, due to rising demand and domestic production that was expected to remain flat, at best (see below chart.)
The Energy Information Agency (EIA) also expected US natural gas imports to increase steadily, reaching 3.5 trillion cubic feet
(TCF) of LNG imports this year, on their way to 6 TCF per year by 2022. As a consequence, in 2005 the EIA forecast that coal would still generate 48% of US electricity
Now imagine energy prices in this alternative 2013. With US natural gas suppliers importing an average of 90 LNG tankers
per month, would the wellhead price of gas still be under $4
per million BTUs, or closer to the $16 price
paid in some international markets? And with US refiners importing up to twice as much crude oil as they are actually on track
to do this year, in the context of sanctions on Iran and turmoil in North Africa, how likely does it seem that oil would be at $105-110/bbl
, instead of much higher? $100 oil is a drag on the economy, but US consumers have adjusted to gasoline priced around $3.50-3.75/gal
., on average. Every $1 per gallon above that would take another $130 billion per year away from other purchases, with adverse effects on the US economy.
More to the point, in such an environment how much tolerance would there be for opposition to oil pipelines or gas drilling that had the potential to lower energy prices, or at least reduce imports and enhance energy security? If oil were above its 2008 high of $145/bbl, and gasoline flirting with $5 per gallon, it would surely be much harder for elected officials to delay approving projects like the Keystone XL pipeline, or to sustain gas drilling moratoria. Ironically then, the successful large-scale application of shale drilling techniques, which has resulted in a 29% increase
in US natural gas production and 33% rise
in oil production since 2004, helped make it possible for opponents of Keystone or fracking to be heard, rather than dismissed out of hand.
I was recently struck by a reported remark by a pipeline executive. "Shale is everywhere," he said, but it won't be produced everywhere because "people make choices."
I agree with that insight, while recognizing that such choices are available mainly because altered economic conditions and some of the same technologies to which some now object have enabled us to shed an energy crisis mindset. This situation might have future parallels for other technologies that have escaped much pushback, so far.
Dr. YM Shum - Chief Technology Advisor
and Director of Exploration Dr. Shum has over 40 years experience in the international petroleum industry and is widely recognized as a leader in the international oil industry in China for his ground-breaking achievements, including the first successful international discovery of oil in offshore China. He also led the team that developed the largest enhanced oil recovery operation in the history of the industry, which was located in Indonesia, and was head of Texaco’s office in Beijing for almost a decade.
China opened its entire offshore area for cooperative development with foreign oil companies in the late 1970's. All of the participating global oil companies formed their own group with the responsibility to conduct a general seismic survey of certain designated offshore areas, to be followed by data processing, interpretation, mapping, reporting and then making presentations to the relevant Chinese authorities, in preparation for the first round of offshore bidding. In the meantime, drafting of the first standard Chinese Production Sharing Contract, known as a PSC, with the help of foreign oil companies was in progress. Frank Ingriselli
was a leading member of the Texaco team negotiating this first Chinese PSC, and I was on the team helping to facilitate because I am a reservoir engineer specializing in oil field development and thermal recovery, as well a native Chinese speaker.
For the first round of bidding, companies formed their respective bidding groups. Texaco teamed up with Chevron, Exxon with Shell, etc. We at Texaco and Chevron had identified blocks 16/08 and 40/01 in the South China Sea as among the best to bid on. At the end we decided to bid for block 16/08, while Exxon and Shell chose to bid for block 40/01. We were all so glad that we made the right choice and received block 16/08. Over time it turned out to be the most productive block in the South China Sea, and I would say that it is the “Golden Block” of the South China Sea, much like the Brent Field is the “Golden Block” in the UK North Sea!
Before the awarding of block 16/08 to the Texaco/Chevron group, the Chinese added the Italian oil company, Agip, to the group, and the group was thereafter known as the ACT (Agip/Chevron/Texaco) Operation Group
. The PSC was signed just before Christmas 1983.
Frank Ingriselli in toast with Minister of Petroleum Tang Ke at signing of historic contract in 1983
Chinese Premiere Li Peng at the historic signing
Frank Ingriselli initialing pages on the historic first successful foreign Production Sharing Contract in China in 1983
Exploratory drilling commenced immediately, and the first exploration well, HZ21-1, was a very significant discovery, the first in the South China Sea, with a water depth in the field area of about 100 meters. Following several successful confirmation/delineation wells, the Huizhou 21 oil field (the “HZ Field”) was developed, and began producing in 1989
, just six years after the PSC Frank Ingriselli had negotiated was signed. This was the first commercial oil production in the South China Sea, producing at an initial rate of 20,000 b/d. The production streams from wells were tied to a well head platform for initial processing, then flowed into a nearby FPSO (floating, production/processing, storage, and off-loading vessel), which was in excess of 200,000 tons. The oil was then off-loaded to oil tankers and shipped to destinations, mostly to refinery terminals in China. Thus the crude oil sales were made at a premium price. The well head platform was equipped with a heavy duty rig for drilling, completion and work-over as required, and was a very cost effective development operation.
According to the signed PSC, CNOOC (China National Offshore Oil Company) participated 51% in the HZ Field development, while the three ACT group companies each owned 16 and one-third percent. The partners continued to explore the block through long reaching directional wells tied back to the well head platform and FPSO, and this has yielded several discoveries, and expanding the HZ Field development. The field eventually reached a peak production in excess of 150,000 b/d. The field is still producing at a good rate after 25 years of continuous production since 1989! Thus the HZ Field has provided a sizable profit and cash flow to its owners to grow their respective businesses in the world.
When the HZ Field was first developed, we had made allowance for water injection for pressure maintenance to increase recovery from the field, with water injection wells drilled within the oil column near the oil/water contact as part of the initial field development. Later on, we learned that the HZ Field was actually connected to a huge water aquifer, and there was no need for water injection, which resulted in a great saving in field development capital. In addition, the 16/08 block was full of oil -- filled to the spill point – with every drillable structure mapped in the block filled with oil!
There is no doubt that the HZ oil field and block 16/08 is the best block ever discovered in the South China Sea. Development was well planned and cost effective, and we have been able to keep it producing for a very long time, with production expected to continue well into the future! It continues to be the great success story of Chevron/Texaco’s operations in China.
Golden Block 16/08 - the Huizhou 21-1 oil field is still producing after 25 years of continuous production (courtesy of CCTV.com)
Nanhai Faxian - the FPSO used in the Huizhou 21 Oil Field. The FPSO is detachable, enabling the vessel to be disconnected and sail to safe place when severe typhoon is approaching. (Photo courtesy: MarineTraffic.com)
Photo courtesy: CCTV.com
As Pacific Energy Development completes its first extended length lateral of over 8000 FT and 33 frac stages after drilling four wells, it is interesting to compare the development of its Niobrara asset to what is happening in shale assets overseas. Horizontal drilling and completion technology has revolutionized US onshore oil production with the discovery of numerous oil shale plays. The International Energy Agency (IEA) has even actually predicted that the United States will be the largest oil producer in the world by 2020. Due to this success, many people have been predicting a similar surge of production internationally completely from shale based production growth. The reality has been somewhat different from the expectation in that infrastructure, pricing, political, and regulatory issues have delayed this growth possibly for decades in many countries.
In terms of infrastructure, many countries lack the technological services and pipeline systems to effectively develop shale assets. Without an existing midstream network, it is difficult to invest hundreds of millions of dollars in pipeline services for a remote region where development is not guaranteed. Without experienced personnel and technological service companies, it is challenging to develop shale oil or gas assets which do not produce any oil or gas without the appropriate treatment and drilling techniques. To give a relative idea of how far off technology is in Europe, the largest frac job ever performed is a nine stage well in Ukraine with a lateral length of ~3000 ft
Compounding these problems is that mineral rights are not owned privately overseas. Due to larger concessions being granted for acreage, there is a lack of competition within areas which inherently slows down experimentation and trying of new techniques. Using the US as an analogue, it was not the large companies, like Shell and Exxon, that led the shale revolution but small independents that were willing to fail over and over again until they found the secret recipes for success. From a regulatory and political standpoint, there has been a severe backlash against hydraulic fracturing overseas. Without having decades of understanding in the safety of technology, many areas of the world have attempted to ban it. What is especially interesting about this is that over 1,600 wells have been drilled within the City of Fort Worth with few ill effects.
Finally, many countries have long term pricing contracts which are not directly tied to the costs of production. Shale oil and gas development has a large capital cost compared to drilling conventional high permeability wells. Given how traditional production sharing contracts work, it would be very challenging in most areas to economically develop a shale gas asset.
In spite of all this negativity, there appears to be a bright spot overseas in China. The government there has made it a priority to develop shale assets providing relatively stable and high pricing compared with the rest of the world along with numerous incentives for success. They have made it a point to buy interests in US oil and gas operations to train staff to take the technology home. Finally, they are actively drilling and testing horizontal shale wells exceeding the European record leading shale technology growth overseas. It will be curious to see how development continues to grow within countries such as China where shale exploration is actively encouraged by its government vs. other countries where it appears that fracing is still a four letter word.