Saturday, August 10, 2013

Peak Oil Demand: Near or Far?

An article from yesterday's Washington Post "Is peak oil demand just around the corner?" is, in part, a summary of an article that appeared recently in The Economist ("Yesterday's Fuel").

Citi recently predicted that world oil demand may peak by 2013 because of increased transport efficiency among other factors.

The Washington Post piece features a discussion with Stanford's Adam Brandt who is skeptical about predictions of oil demand peak.

Brandt thinks the demand story is more complex because of the rise in unconventional sources for transport fuel including natural gas, biofuels and oil from tar sands, not to mention electric vehicles.

Brandt doubts that auto fuel efficiency will continue to increase has it has in the recent past and sees a potential explosion of transport demand from Asia.  

He further invokes Jevon's Paradox to suggest that easier and more pleasant driving from Google autonmous vehicles and driving errand outsourcing may in fact increase transport fuel demand.  The past is not necessarily the key to the future.

Wednesday, August 7, 2013

Wood Mackenzie Says Bakken & Eagle Ford Will Produce More than the Two Largest Fields in North America Combined

Wood Mackenzie reported on July 30, 2013 that U.S. shale plays will produce 5 million barrels of oil per day by 2019, at least half coming from the Eagle Ford and Bakken shale plays.  Naturally, most people believe this without asking the obvious question, "How does this huge volume of oil compare with present U.S. production or the largest fields in the world?"

The U.S. produced 7.3 million barrels of crude oil per day in May, 2013 and reached peak production of just over 10 million barrels of oil in 1970.  WoodMac would have us believe that U.S. oil production will exceed peak production by about 2 million barrels per day, and will increase present production by almost 70%.  That would be awesome but seems highly unlikely based on the history of oil production decline in countries and basins around the world.

This is like telling the average American whose life expectancy is 79 that, by some miracle, we can all now expect to live to be 115 years old.  Never mind that only one person is known to have lived to be this old, it's still reasonable that everybody will live this long! Hmm.

Back to oil production, Ghawar, by far the largest oil field in the world with 74 billion barrels of reserves, produces 5 million barrels of oil per day and never produced more than 5.7 million barrels.  We are, however, supposed to believe that shale plays--the Bakken and Eagle Ford, in particular--will equal Ghawar.

Cantarell, the largest oil field in North America with 19 billion barrels of reserves, produced 2.1 million barrels of oil per day at its peak.

Prudhoe Bay, the largest oil field in the United States with 13 billion barrels of reserves, produced 1.5 million barrels of oil per day at its peak.

WoodMac would have us believe that the Bakken and Eagle Ford will almost equal production from the two largest oil fields in North America combined.  I certainly hope that they are right but history and facts suggest that this estimate is at best highly optimistic and, at worst, exaggerated.

As far as I know, the WoodMac report is not publicly available so I cannot comment on how they arrived at the numbers.  How could they be wrong?  I would first look at the per-well reserves and decline rates used in this estimate because these have been unrealisticallly optimistic for all shale plays so far.  Second, I would look at the size of the commercially productive area they assume for these plays because these have also been unrealistic for other shale plays.

Everybody likes good news but we all hate disappointments.  In a world of dwindling oil resource opportunities (that's why we are drilling shale, after all!), it is time to start changing our behavior and using less oil.  Reports like this give people the message that there is no reason to change our wasteful practices.  Don't worry, be happy!

Saturday, August 3, 2013

Shale Plays Not Working For Big Oil

Recent revelations and write-downs of shale assets in North America by Shell, ExxonMobil and Chevron support our research that big companies cannot make money on low rate-low volume shale wells.

The majors exited North America in the 1980s because they could not support the operating costs associated with managing this kind of production even though the wells were profitable.  They went to the overseas arena where things worked for a few decades as deep water plays emerged.

In the last 5 years, international opportunities have been exhuasted and national oil companies hold all the cards.  This means that remaining international opportunities carry onerous production-sharing agreements or other difficult contractual obligations (note the deals that Shell, etc. have entered in Iraq where they must spend $billions to get a $2/barrel payment for incremental added production--these deals are being re-considered.

So, the majors jumped back into North America with the lure of large reserves from shale.  This trend began when ExxonMobil acquired XTO Energy in early 2010.  At the time, this was viewed as a validation of shale plays and their economic viability.  I refer you to my comments about this acquisition in February 2010:

"The mainstream belief that shale plays have ensured North America an abundant supply of inexpensive natural gas is not supported by facts or results to date. The supply is real but it will come at higher cost and greater risk than is commonly assumed. The arrival of ExxonMobil and other major oil companies on the shale gas scene is positive because they will not follow the manufacturing approach, and will do the necessary science that should make shale plays more commercial. This does not, however, ensure success.

"ExxonMobil has come late to the domestic shale party. They may have overvalued XTO's existing wells without fully taking high production decline rates into account. It is also possible that XTO has already drilled the best areas in more mature shale plays, while the potential of newer plays has not yet been established. It is unclear how ExxonMobil’s enormous overhead structure and its associated cost will fit with operating thousands of relatively low-rate gas wells."

Now that the shale plays are not working at least for the major oil companies, what next?

I believe that we are seeing the slow liquidation of these organizations but they cannot let the investment public know that this is what is occurring, hence the cornucopian rhetoric about the shale revolution and North American beoming the next Saudi Arabia--pure poppycock, of course.  Will the recent write-downs and announcements affect investors?  Probably not for now.

Sunday, July 21, 2013

British Geological Survey Bowland Shale Gas Assessment

(The original post appeared on The Oil Drum, July 19, 2013)

The latest exuberant shale gas news comes from a report by the British Geological Survey estimating enormous new shale gas resources in the central UK. On June 27, 2013, the British Geological Survey (BGS) released a natural gas resource assessment for the Bowland Shale in the United Kingdom stating that approximately 40 trillion cubic metres (1,300 trillion cubic feet (Tcf)) of shale gas exist in 11 counties in northern England. The BGS report, unfortunately, only addresses gas-in-place (total resources) and not extractable resources (technically recoverable resources) much less reserves (commercial supply). The most-likely reserve potential of the Bowland Shale is only about 42 Tcf (3% of gas-in-place) after applying methods used by the U.S. Energy Information Administration (EIA) and Potential Gas Committee (PGC).

The potential for misunderstanding of shale resource estimates is great. Various organizations have published resource estimates for shale gas plays in the U.S. and around the world. These reports are commonly misinterpreted as representing commercially producible volumes of gas.

Resources are the volume of natural gas in a particular formation, also known as gas‐in‐place. This has no relation to what is physically or technically producible much less commercially viable. The technically recoverable portion of total resources--Technically Recoverable Resources (TRR)--is that volume that can be produced using present technology. It similarly does not include commercial factors. This is the gas volume most often publicized and confused with reserves, the economically producible subset of technically recoverable resources. The EIA states that TRR represents approximately 25% of gas-in-place for most shale formations.

Technically recoverable resources are generally divided into three categories based on uncertainty. According to the PGC, probable technically recoverable resources are those gas volumes that are currently being produced in gas fields such as, for example, the Barnett or Marcellus shale plays. Although the history of production is only a few years to perhaps ten years, there is some degree of confidence in projecting ultimate recovery from early producing rates. Possible resources are thought to exist based on new field discoveries. In this category, there is little production history and large areas of potential gas development must be inferred. Speculative resources are gas volumes that are thought to exist but that have not yet been drilled. These clearly have great uncertainty. Reserves are the volume of technically recoverable gas resources that can be produced at a profit based on present assumptions about cost and price. Supply is the much smaller portion of reserves that has been developed and connected to infrastructure so that it is available on demand to consumers.

I first applied the EIA guideline of 25% Gas-In-Place to determine TRR for the BGS low, high and most-likely gas resource cases for the Bowland Shale. Next, I used the relative percentages of probable (32%), possible (43%) and speculative (25%) TRR taken from the PGC's latest assessment of the U.S. technically recoverable resource base. Finally, I assumed that 50% of the Speculative TRR would be commercially producible, since there is no production from the Bowland Shale, and used this value as the potential reserve estimate.

This approach suggests that the most-likely reserve for the Bowland Shale is approximately 42 Tcf. While this is a substantial volume of gas (roughly equivalent to the Barnett Shale accumulation in the U.S. based on a recent evaluation by the Texas Bureau of Economic Geology in press), it is hardly the amount of gas reported by the mainstream media based incorrectly on the total resources reported by the BGS.

The larger problem for the U.K. and all developed countries is energy for transport fuel and natural gas will not solve that in anything less than decades at best. I want to dispell the mistaken notion that energy sources can be freely substituted. Just because there is another 14 years of potential gas supply for the U.K. because of the Bowland Shale, how hopeful is that in the long-term view of many decades before other energy sources may constitute a meaningful percentage of total energy demand? Also, why do we have to use supply as fast as we can?

Then there are the obvious issues that will challenge development of this resource like public opposition to the physcial footprint of development--based on well productivity from the Barnett Shale, it will take approximately 30,000 wells to fully develop the Bowland Shale potential reserves--and the lack of incentives for landowners (the state owns oil and gas mineral rights in the U.K.) to participate since there is no commecial benefit for them. Also, there is no guarantee that this play will work geologically or be commercial.

While the Bowland Shale is the same geological age as the Barnett and Fayetteville shales in the U.S. and is known to be an oil source rock like the U.S.shales, there is no evidence to suggest that U.S. shale production is an analogue for Bowland gas-producing potential. Among the most important factors in shale gas play performance are high organic content, high thermal maturity and high silica or limestone content. These produce brittle shale reservoirs with large volumes of available gas. High organic content also results in creation of important porosity where kerogen is converted to gas because of a volume change.

So far, there is little geochemical data for the Bowland Shale and, while some of the data appears to be in a similar range as for the Barnett Shale, lack of comprehensive data is a risk factor in assessing the potential of the play. Each shale gas play is different and, until industry knowledge is greater, must be viewed as a “one‐off” opportunity with a considerable learning curve, unanticipated costs and commercial risk.

Tuesday, July 16, 2013

A Few Words About Peak Oil

(Note:  This post originally appeared in The AAPG Explorer, Februrary, 2013)

Steve Trammel of IHS stated in the January EXPLORER (“Surprise! North America Grabbed the Spotlight”), “The Peak Oil guys are pretty quiet now, thanks to the creativity and innovation of the industry,” as he discussed the tight oil additions to oil production in the United States and Canada.

I am on the board of directors of the Association for the Study of Peak Oil (ASPO USA), and I can assure you that we are not quiet nor do these additions change our concern about the growing cost of oil and its effect on our economy.

In the past month alone, we held a major conference in Austin co-sponsored by the University of Texas, a great advocate for the oil and gas business (Texas leads the United States in both oil and gas production). Right after the conference in Austin, a group of our members presented a panel discussion at the fall American Geophysical Union meeting in San Francisco.

In the same month, we were invited to spend two hours with Adam Sieminski, the new Administrator of the U.S. Energy Information Agency (EIA), and all of his top line staff. On the same day, we met with the new chairman of the Senate Natural Resources Committee, and with a former senior senator who is now among the leading energy lobbyists in Washington.

Some people take us very seriously because they understand that “peak oil” does not mean we are running out of oil. It means that we have run out of the cheap oil on which the global economy is predicated. That is serious business.

We also applaud the creativity and innovation of the industry that has increased U.S. production over the past few years. It is, however, very expensive oil. Tight oil requires at least $80 per barrel for operators to break even because of the cost of horizontal drilling and hydraulic fracturing, not to mention the unprecedented leasing costs that the shale revolution has brought to our industry.

The high price of oil is among the key underlying reasons that the United States and most of the developed world cannot get out this recession. Gross domestic product (GDP) and oil consumption correlate because the economy runs on energy, and oil and its refined products are the largest component of primary energy consumption.

Because of the high price of oil, consumption in the United States has fallen 1.5 percent per year since 2005, and GDP has followed suit. Pre-2005 normal growth for the U.S. economy was 1.8 percent per year. With an annual 1.5 percent decline built in, it is not hard to see the problem with resuming growth.*

The IHS tight oil study Trammel quotes is confusing because it combines Canada and the United States. Canada has been energy self-sufficient for decades and is the leading oil exporter to the United States – any production additions from Canada are still imported oil for the United States.

The EIA estimates that U.S. crude oil production will increase to nearly eight million barrels per day by 2020 and then decline. Present consumption is almost 15.5 million barrels per day. If EIA is correct, the United States will still have to import about seven million barrels per day allowing for demand decline, and that does not look like energy independence to me.

Most of the exuberant reports about energy self-sufficiency from domestic production lump crude oil, natural gas liquids, refinery processing gain and biofuels as “liquids.” That is fine, but we must bear in mind that what we import is crude oil and today, we cannot use other liquids for transport – the main use of crude oil – without massive equipment and infrastructure changes that will cost trillions of dollars and take decades.

These same optimistic reports almost never consider cost, price or profit margins.

The new production we are finding from tight oil is both important and exciting, and it will help make the United States less dependent on foreign crude oil. It will not, however, make us energy independent.

Peak Oil guys like me are hoping that at least people in the oil and gas business will realize that we have a problem that is not going away.

(*All data in this section from Douglas-Westwood.)

(Editor’s note: Berman, an AAPG member, is with Labyrinth Consulting Services in Sugar Land, Texas.)

Saturday, February 16, 2013

Lessons From Past Natural Gas Import Fiascos Suggest A Cautious Approach to Natural Gas Exports

The U.S. should take a cautious approach to exporting natural gas.

That’s the clear lesson of three decades of bad guesses by analysts about natural gas prices and supplies. If pro-export advocates are wrong this time, consumers and businesses will be the ones who suffer from higher domestic gas prices.

Several recent studies concluded that domestic price increases from exports would be small. This conclusion, however, is based on unrealistic assumptions about the size of U.S. gas supplies and the true cost of producing shale gas.

In fact, supplies are likely substantially smaller than predicted, while costs are higher.

History should provide ample reasons for the U.S. to look before it leaps into large-scale exports. Two cycles of investment fiasco involving natural gas imports to the U.S. have occurred in the past 30 years, first in the 1970s, and again just a few years ago, when more than 47 applications for natural gas import terminals were pending at one point.

Both of these were due to incorrect predictions about domestic supply. The supply models that past gas import decisions were based on had widespread support by experts. But they were wrong.

The lesson: gas supply estimates are much more uncertain than experts and conventional wisdom assumes.

Now, a new supply model has replaced the previous one and analysts again agree upon natural gas abundance at low prices for decades to come. Our analysis - which we plan to publish on in coming days - suggests that they are wrong again.

We do not dispute that the shale gas resource is large; we question the near- to medium-term supply, the amount of shale gas that is available on demand. The number of gas-directed drilling rigs has plummeted in the past year because of low price and we fear that demand may exceed supply unless this trend is reversed.

All oil and gas wells display production decline rates over time. The decline rate is simply the change in flow over time. Shale gas wells have especially high decline rates, meaning U.S. supplies are likely shorter-lived than many are predicting. For example, conventional gas wells decline at annual rates of about 20% per year but the production from shale gas wells declines at rates of at least 33% per year and often higher.

Furthermore, the cost of production is likely more than the prevailing market price based on company filings to the government.

Thousands of wells that have been drilled have not been turned on yet. As these wells come on line, supply rates will be maintained at high levels despite decreased drilling for a while. When this excess capacity is reduced over the next year or so, U.S. supply will decrease unless gas drilling resumes and this will not happen until prices rise.

Production from shale is a new phenomenon and prediction about future well performance is speculative. Recent studies, however, by the U.S. Geological Survey, the University of Texas, Louisiana State University and other industry groups show that commercially recoverable per-well shale gas reserves may be considerably smaller than some believe.

Despite assumptions that gas prices will remain low, ExxonMobil Chief Executive Rex Tillerson says that his company is making "no money" on U.S. natural gas due to low prices that have fallen well below the cost of production.

“We are losing our shirts,” Mr. Tillerson told MarketWatch last June.

In recent weeks, a coalition of gas users that include Dow Chemical Company warned that gas exports would increase domestic prices and that in turn would cause a loss of competitive advantage for U.S. business. They are correct.

Energy from domestic gas is a strategic natural resource and, therefore, should be given special attention before approving its export. Just because we have abundant natural gas, why should we race to use it up as fast as we can?

We recommend allowing spot cargo exports on a trial basis for two years. This pilot project should not contractually bind export volumes of more than 3.0 billion cubic feet per day, approximately 4% of daily U.S. consumption. In two years, we should have a much clearer understanding of the capacity of shale gas to support internal supply.

Past ExxonMobil CEO Lee Raymond cautioned last year, “There is going to be a big debate in the U.S. as to whether or not they’re going to permit the export of liquefied natural gas. Even if you get past the politics, you have to test whether or not the resource base is sufficient.”

We agree. Approving long-term export contracts before confirming the true size of U.S. natural gas supplies would be reckless. Policymakers should take the time to get it right, so the rest of the country does not pay the price for another cycle of bad guesses about the natural gas market.

Arthur E. Berman, Petroleum Geologist
J. Michael Bodell, Oil and Gas Price Stucture Specialist and Petroleum Geologist
Henry Groppe, Chemical Engineer and Founder, Groppe, Long and Littell, Oil and Gas Supply Demand and Price Analysts.
Rune Likvern, Natural Gas and Oil Supply and Demand and Systems Analyst and Economist
Tadeusz Patzek, Petroleum Engineer and Chairman of the Department of Petroleum &
Geosystems Engineering at The University of Texas at Austin
Lyndon F. Pittinger, Petroleum Engineer

Tuesday, January 1, 2013

Industry Experts Know Less Than College Professors and Journalists About Shale Gas Economics

A recent article by Ken Maize in Power mistakenly assumes that university professors who have never worked in the oil and gas industry know more about evaluating oil and natural gas well economics than industry professionals who have spent their careers doing this work.

In "Is Shale Gas Shallow or the Real Deal?", Maize cites Dr. Terry Engelder's opinions about shale gas versus ours.  Terry is a friend and colleague who I respect and sometimes participate with in panel discussions about shale gas.  He is a late adopter of oil and gas reserve forecasting after a career in structural geology.

Maize confuses Terry's work on resource assessment with our work on reserve forecasting because he is a journalist and doesn't understand this important distinction.

Resources are the total volume of oil and gas regardless of cost, while reserves are the small fraction of resources that can be produced commercially.

The debate is simple.  Are shale gas wells commercial failures or not?

Rex Tillerson, the CEO of ExxonMobil, stated about shale gas, "We are all losing our shirts today." Mr. Tillerson said in a talk before the Council on Foreign Relations in New York. "We're making no money. It's all in the red."

Independent evaluations of shale gas plays by the United States Geological Survey, the Bureau of Economic Geology (University of Texas at Austin), and the Louisiana State University Center for Energy Studies all corroborate our well reserve estimates for shale gas wells.

There is no debate.  Maize's article is contrived and Engelder is wrong.