Can US Natural Gas Production Be Ramped Up?

Navigant Consulting Inc (NCI) recently prepared a report called North American Natural Gas Supply Assessment on behalf of a natural gas organization called the American Clean Skies Foundation. In this report, NCI estimates the amounts shale gas and tight gas production can be increased in the next decade. These estimates suggest that US natural gas production can be ramped up by nearly 50% by 2020. How reasonable are these estimates? What obstacles are there to such a big ramp up?

Figure 1. Approximate future US natural gas production, based on Navigant Consulting estimates of shale gas and tight gas production.

My analysis indicates that NCI is correct in some respects. There is indeed a great deal of unconventional natural gas resources in the United States, and recent improvements in technology point to the possibility of significantly greater production.

There are two major problems, however. One is that short-term demand is not very flexible. It is very easy to flood the market with more natural gas than the market can absorb. The other is that there are a number of obstacles ahead for companies selling natural gas. It is likely that these obstacles, rather than a lack of natural gas, will curtail the rise in natural gas production. As a result, the full ramp up in production is not very likely.

Recent EIA Data for Natural Gas

Let's start by looking at EIA natural gas data. EIA has recently reported a big increase in US natural gas production (8.8%, comparing the first five months of 2008 with the first five months of 2007). Some have suggested that the EIA numbers must be wrong. It seems to me that what we may be seeing is the effect of a recent technological breakthrough.

Until fairly recently, many of us had noticed a pattern of increased drilling being required to achieve the same quantity of natural gas production. Most of us interpreted this to reflect declining Energy Return on Energy Invested (EROEI).

In the last few months, there has been a sudden shift in the data. EIA data shows that recent production is rising at the same time that the drilling of new wells is leveling off. Average daily dry gas production during the first five months of 2008 is up 8.1% over the same period in 2007. (Because 2008 is a leap year, total dry gas production has increased 8.8% for the five month period.)

Figure 2. US dry gas production has been rising since about November 2007

Figure 3. Number of natural gas wells drilled levels out, about the same time production begins to rise (November 2007)

Figure 4. Number of natural gas drilling rigs levels out in late 2007

One can look at many other measures as well, and see a similar pattern. The number of well feet drilled per day levels off and even drops, in late 2007 and early 2008, at the same time natural gas production increases. My interpretation of what is happening is that there has been a technological breakthrough, probably in the area of shale gas production of natural gas. Because of this breakthrough, companies are able to produce more gas, with less drilling effort.

There are several reasons I believe that the data reflects a technological breakthrough, rather than, say, an error in EIA data. First, when I look at individual company reports, the ones that show drilling activity seem to show the same kind of pattern--more success with fewer wells drilled. Also, even where there is not information on the number of wells drilled, the company reports talk about increased productivity of wells, due to the increased use of horizontal drilling and better fracturing techniques. Finally, the increased natural gas in the system is having the expected impact on storage and prices, as I will discuss later in this post.

EIA does not break out recent production into unconventional vs. conventional. In fact, the most recent break out of unconventional is for 2006, given in the backup data to Figure 80 of the Annual Energy Outlook:

Figure 5. EIA History of Forecast of Natural Gas by Source

It is clear from looking at this figure that unconventional gas has been rising rapidly. EIA's forecast for the future looks unreasonably pessimistic alongside its production history. The other two major categories (onshore conventional and offshore conventional) are both declining rapidly (but miraculously are forecast to rise in the future).

The EIA graph in Figure 5 shows that there is the potential for an increase in gas production from Alaska, once a pipeline is built. The EIA forecasts that this will happen in 2020. The amount of the increase appears to be about 10% of current US natural gas production. If this in fact takes place, on my Figure 1, there will be a small bump up in production in 2020, bringing the 2020 production total from 29 trillion cubic feet to 31 trillion cubic feet.

If there is an increase in overall natural gas production, one might reasonably assume that the increase in unconventional natural gas is finally overpowering the decline in conventional production. EIA data by state and information from company financial reports both point to success with shale gas, particularly Barnett shale in Texas. If the recent increase in production in fact relates to shale gas, this would tend to tie what is happening now to what the Navicgant Consulting, Inc.(NCI) analysis is forecasting for the years ahead.

Navigant Estimates

NCI in its report does not make an estimate of total US natural gas production. Instead, it makes estimates of shale gas and tight gas production, in very general terms. In Figure 1, I put these estimates together with some rough estimates of the remaining pieces to get an estimate of expected future natural gas production. (I used a 3% annual decline rate for conventional natural gas.)

NCI's forecast of shale gas production is in terms of how much sustainable production might be expected from the various shale formations:

Figure 6. Navigant Consulting Inc (NCI) forecast of future shale gas production

The timing is not given very precisely, just "next decade". In Figure 1, I assume that this higher level of production will not be reached until 2020. Because of the imprecision of the wording, a person could argue that production might reach this higher level as early as 2015.

With my interpretation of the NCI report, indications are that shale gas is now the big source of growth, and will continue to be in the future. Tight gas production will also continue to grow.

Figure 7. Breakdown of Figure 1 forecast of unconventional gas into tight gas, shale gas, and coal bed methane

Previous unconventional gas posts

Many readers will remember that I have written previously about unconventional natural gas:

US Natural Gas: The Role of Unconventional Gas

US Natural Gas: Lessons from BP's Tight Gas Facility in Wamsutter WY

In these posts, I talk about how widespread shale gas and tight gas are. I also talk about the advances BP has been making in its Wamsutter, Wyoming tight gas facility. With this as a background, it is easy for me to believe that if all of the resources are there, there is a reasonable possibility that US unconventional production can be ramped up further. I think there are obstacles that may get in the way of this, however.

Short term problem: overwhelming the system with too much gas, and causing price to drop

What happens when one increases natural gas production by 8% per day? There are a few places this can go--a little to offset a decline in imports from Canada, a little to use as exports to Canada and Mexico, and a little to meet the growing demand of electric utilities. Liquefied natural gas (LNG) imports can be reduced to their contractual minimum. On the industrial side, some factories with spare capacity can use some additional natural gas. It is difficult for these uses to absorb the 8% growth in production, however.

How could you individually increase your own natural gas use? You could turn up the thermostat to heat your house more in the winter, or you could use more electric appliances if you have electricity from natural gas. There really isn't much else you could do, without purchasing something new (for example, a clothes dryer that runs on natural gas, or a car that runs on natural gas). It is not a whole lot different for business users of natural gas.

Once demand is satisfied, the remainder is added to natural gas underground storage. This past week, 102 billion cubic feet were added to storage; the week before 88 billion cubic feet were added to storage. The US is currently producing about 56 billion cubic feet of natural gas a day, so over the past two weeks we have put about 20% of production into storage.

Figure 8. Recent EIA Natural Gas Underground Storage Graphic

The problem is that natural gas underground storage is not terribly large, and it hasn't been increased recently in size to accommodate the new larger natural gas production. Historical data suggests that the practical limit of working storage is 3,600 billion cubic feet. This is a bit over two months' production. As of August 22, 2008, the amount of natural gas in working storage was 2,757 billion cubic feet, leaving only 843 (= 3,600 - 2,757) billion cubic feet of "space" available.

Once storage fills up, there is no other place for the natural gas to go. To make matters worse, it is very difficult for producers to shut production in, if there is no space available for storage, so producers will mostly continue to produce, whether or not there is space available.

Once traders realize that there is a significant chance that natural gas production will exceed storage space, prices start to drop. It seems to me that this is part of what has happened with natural gas prices recently. One consideration in deciding whether the supply will exceed the storage space is the long range weather forecast. The forecast is for a warm fall, meaning that little heat will be needed. We are also in the midst of an economic slowdown, and this is also likely to reduce natural gas use.

All of this makes for a bad situation for natural gas producers--lots of supply, but not enough demand, and prices dropping disproportionately to the prices of other fuels. In another post in the next few days, I will talk various approaches that have been proposed to increase demand, so as prevent this problem. I will also talk about the quantity of gas that might be available.

Other obstacles to growth

It seems to me that the main issue is not whether there is enough natural gas in the ground. It is whether we will be able to get it out and transport it to users. It seems likely to me that one or more of the following will reduce growth to significantly below what theoretical studies would suggest:

Not enough distribution pipeline and underground storage
Every company adding new production will realize that it needs pipeline to connect its gas to an appropriate processing center. It may not be as obvious that the distribution system as a whole is likely to need to be expanded, if significantly more natural gas is produced. For example, if natural gas is to be used to replace heating oil in the Northeast, it is likely that both more underground storage and more distribution pipeline will be needed. (See this post by Heading Out.) Expanding the distribution system is likely to be expensive and take several years.

Worn out pipelines
Matt Simmons has repeatedly stated that pipeline infrastructure is nearing the end of its useful life. If this is true for natural gas, this could be a problem.

Not enough of the right kind of drilling rigs
If everyone wants new horizontal drilling rigs, this will be a bottleneck to growth, until enough new rigs of the correct type can be built.

Not enough pipe
There have been articles in the press about steel for drilling pipe and casing being in short supply.

Not enough trained manpower
This is a problem in any industry that tries to ramp up quickly.

Reduced credit availability
Banks have cut back on their lending. Natural gas companies that have depended on a lot of leverage in the past will find this business model very difficult to maintain. I expect them to either slow down their rates of growth, or partner with an oil major who is in a better position financially.

Counter-party risk
Quite a few of the natural gas companies are major participants in the derivative markets. We know that many banks are in financial difficulty. If banks in financial difficulty are counter-parties on transactions, their defaults may cause financial problems for the natural gas companies.

Issues with water re-injection or disposal
Unconventional gas production requires re-fracturing of wells from time to time. The fluid used in re-fracturing must be disposed of properly. There was recently considerable opposition to shale gas drilling in New York because of water issues.

Declining profitability
This is closely tied to EROEI. If there continue to be advances in technology, I would not expect this to be a problem. Some of the sites may prove to be more difficult to extract than the NCI forecasts, and this could be a problem. There is also the possibility of external impacts, such as higher taxes.

Peak oil
Peak oil will reduce the availability of oil for every use. It is hard to think of an allocation scheme that would fully protect the unconventional natural gas industry. The workers all need cars to get to work; food needs to be transported to the location where there workers are working; and drilling rigs often diesel powered. Any oil disruption could interfere with natural gas drilling.


My congratulations on your excellent study of the natural gas situation. What I find confusing is that just a few months ago, gas prices were extremely high and North America has been in the "Red Queen" dilemma of running harder and harder just to stay in the same place. Now suddenly, many people are going into the cornucopia mode.

Do you have any idea how large unconventional gas reserves are or how quickly they will deplete compared to conventional gas fields. Does tight gas or Barnett shale hold reserves comparable to the elephant gas fields we have relied on?

There is an incredible amount of resource out there. This is a map I posted earlier regarding tight gas.

Shale gas resources are just as widespread. Even coal bed methane is theoretically very widespread, since veins that are too deep to mine can possibly be used.

These resources will certainly vary in quality from one part of the county to another. Originally, none of it could be extracted profitably. Companies have chosen what appear to be promising sites, and gradually made incremental progress on being able to extract the natural gas profitably and in reasonable quantity. It is yet clear how much of this gas can be extracted profitably, since this will depend on how much technology can be adapted to extract gas in different formations. In some formations, the gas may be so "dilute" or bound so tightly that nothing can be done to profitably extract it.

One of the issues in determining gas reserves is how closely wells can be spaced. The original spacing (I believe) was one well to 80 acres. This is now coming down to one well to 40 acres in some places, and even one well to 20 acres a few places.

In my visit to BP's Wamasutter WY location, BP said that it has produced about 3 trillion cubic feet of natural gas since 1977. This represents less than 20% of the resource available in BP's portion of Wamsutter field. We were told that gas wells from the 1970s are still flowing.

If we had unlimited resources (including no peak oil), I can imagine a scenario where unconventional gas could keep producing at a high level for 20 or 30 years, because rigs could be moved on to new locations, as old locations became exhausted. In the real world, I doubt that this is will happen.

Cheers Gail and thanks for the excellent article. Just a few thoughts:

1. Doesn't this put a little wrinkle in the 'peak oil' situation? Can we use Nat Gas to release some of the burden on Coal and potentially, oil?
2. As for excess gas, doesn't this play well to the Pickens plan? If we could run 10% of our transport on Nat Gas, wouldn't that help ease any glut while providing a more steady demand? Added benefit -- less foreign oil imports (10% Nat gas + 10% biofuels + 20% efficiency gain +10% all electric might just destroy our imports and achieve the dream of energy independence -- I know, you guys will all cry cornucopia. Just a thought).
3. How much of the gas could we liquefy and export? Europe needs gas bad. Russia is a geopolitical problem. A few bargaining chips other than the navy in the Black Sea would be nice.
4. Can you 'crack' gas into traditional petroleum products? If so, at what cost/EROI?
5. With demand curtailed for oil and new supply of nat gas is the energy market headed for a mini bust?
6. Chemicals/plastics/fertilizer. Bring more industry back to the states. Am I wrong???
7. This looks like one giant opportunity in need of a few good capitalists.
8. Or would it be best just to pace production so we can make the best use of our resource over the longest period?

As for 4: Yes, I think this should be possible. Methane has even advantages to longer hydrocarbon chains as it has a better hydrogen/carbon ratio. So a plethora of natural gas would be a great fix to bridge the gaps opened by peak oil. But I'm still not sure how far the UNG resources provide is a sustainable solution or are only a temporary straw fire (see the comments below).

The Independence Hub and its 0.9 Bcf/day started July 2007. That is one reason that early 2008 is so far ahead of early 2007.

Well worth the wait Gail. An excellent picture of today’s unconventional NG plays. I can back up some of your assertions from the front lines. The technology improvements have been THE key along with supporting NG prices. As an example, 5 years ago a vertical UNG well might be drilled on a 40 acre unit. A year or two later, one horizontal well 1000’ long might be drilled on 80 acres thus replacing 2 vertical wells. This well might be fractured in 3 or 4 spots thus allowing even better results then the 2 vertical wells it replaced. Today, a horizontal well drilled with a lateral length of 4000’ might be drilled on a 320 acre unit. This well may also have 10 or 12 intervals fractured. This latest effort would replace 8 vertical wells drilled just 5 or 6 years ago. The initial production rate might easily exceed that of the combined 8 wells also. Thus there would be a big disconnect between the number of wells drilled and expected results if these advances were not taken into account. It’s difficult to estimate future expectations of advancing technology but I’ll guess we’re getting close to the point of diminishing returns on that front. Some improvements for sure but nothing like we’ve seen in the last 5 or 6 years. On the other hand, new UNG plays are now being explored which have never been considered viable targets in the history of resource development in the USA. With that in mind, any effort to offer a maximum/minimum detailed expectation of future recoveries would be almost pointless at this time IMHO.

With respect to increasing gas storage, this has been one of the most sought after opportunities in the last 5+ years. But there have been significant road blocks. Only certain reservoirs are suitable for NG storage. And this number is limited. Complicating the effort even further is that many such sites are in the Gulf coast region. Adding storage here does little to alleviate demand out side the region due to the transportation bottle neck. Even where potential storage reservoirs are close to the end users it isn’t a sure thing. If the sites are distant to the pipeline system it adds a huge cost factor to make the connection. Additionally, building the new pipeline connections take a considerable amount of time. This adds considerably to the risk of predicting future demand/pricing. And even when conditions are favorable, NG storage is an expensive proposition to initiate. A certain volume of “bunker gas” is needed. This is the volume of gas that will never be produced as long as the facility is operating. A NG storage of significant size night require 10 bcf of such gas or more. At $10/mcf this would tie up $100 million of capital indefinitely.

A significant amount of tite NG sand production is still locked up in the western states due to lack of regional transportation lines. But advances on this front have been made over the last 5 + years.

But, as to the question of these plays being similar to the giant conventional gas plays of old, the simple answer is no…not even close. I’ve worked in some of those old fields where an individual well might produce 30 or 40 bcf over its life time. Cumulative production from some of the best UNG wells might approach this level but the vast majority will produced just several bcf of NG. The production profile of the typical UNG well is very different: a high initial rate with production dropping as much as 70% to 90% in just several years. This is why you’re seeing such an acceleration in new completions. (and given current NG prices these wells do generate a very acceptable, if short, rate of return). As wells drilled just 2 or 3 years ago start their steep decline rates the companies (especially the public one) must drill more wells to replace them. But as these newer wells begin their decline even more wells are needed to replace. Almost all the big UNG players are public companies. As outlined here earlier, these companies must show consistent y-o-y growth in reserve volume. This is how their stock is valued by most on Wall Street. This fact actually adds to the potential recoverable NG values. Even if NG prices were to drop to a level that a public company could only expect to just recover their capital cost they would have no choice but to continue drill as fast as their cash flow would allow. We may actually reach a point where NG prices won’t support continued development of UNG due to over supply conditions. But these periods will be relatively short lived as production rapidly declines.

Many thanks for your comments. Your on-the-ground comments are always helpful.

I was looking at your statement, "The vast majority [of UNG wells} will produce just several over its life time." This fits in with what I was seeing at BP's Wamsutter. They were talking about production of 1 or 2 bcf over a well's lifetime. I hadn't realized that old conventional natural gas wells might produce 30 or 40 bcf over their lifetimes.

I suppose that we could be seeing a "U" in productivity. There is a huge drop down from conventional to unconventional, but now the unconventional could be coming up a bit. With the huge resource there, it is theoretically possible to extract quite a large amount at a low, but acceptable, EROEI.

If my fading memory is correct the highest recovery I've seen from a single well was around 120 bcf from an offshore TX field drilled by Chevron decades ago. It was a one well field...I suspect Chevron didn't realize how big the reservoir was and thus didn't drill additional wells to accelerate recovery.

I also meant to point out something important about the spike from the Independece Hub. The various Deep Water wells tied into it will also have a relatively short life compared to old conventional fields. Don't know the details but I'll guess 5 or 6 years. They may eventually be replaced by new wells down the road but only time will tell. Having the Hub inplace might bring more drilling back to this rather NG prone area.

The natural gas through the Independence Hub would actually be conventional natural gas, rather than unconventional natural gas. It would be good to have a breakdown on conventional vs unconventional in real time, rather than years later. Does anyone have a source that breaks out the amount of this flow separately? Perhaps some of the MMS offshore data, perhaps?

If the new offshore wells are much more productive than the unconventional wells, this could also be skewing the well productivity somewhat also.

In my Figure 1, I made a guesstimate of the 2007 and 2008 conventional / unconventional split. It is possible this split is skewed too much toward unconventional.

I think in your previous post you said that the production per well of shale/tight gas was MUCH lower than a conventional gas well.

Some here seem to be ignoring the fact that Peak Gas will be governed by the 'size of the trap' not the size of the resource(which seems to be growing by the second).

But let's look at the 'natural gas fairy' for a sec.

It takes 127.77 SCF to equal 1 GGE. The US uses 150 billion GGE per year so that works out to 19.165 trillion cubic feet of natural gas. Current US consumption is around 24 Tcf of natural gas so adding domestic production of natural gas just for CNG cars will increase by 80%. We still would use at least 3.65 billion barrels of oil per year and we produce 1.9 billion barrels per year. We would still have to get about 900 million barrels a year from Canada and 600 million barrels a year from Mexico (will Canada's tar sands grow as fast as Mexico depletes?). So we still import 250 million barrels of oil.

How long will our new NG 'potential' last? The USGS says that unconventional gas is around 544 Tcf of gas. Conventional is around
400 Tcf and then there is the ever popular undiscovered potential of something like 300 Tcf. Total ~1200 Tcf. Divided. By. 44 Tcf. Equals. 28 years. (Assuming unconventional gas flows like conventional gas, which it doesn't).

And what do you know... Boone says other technologies will take over in 30 years(probably hydrogen from much more abundant coal)!

'Fool me once...I won't get fooled again', right?

I am happy we have found some more natural gas but I'm not deleriously so.

Could somebody please tell the agents of the natural gas companies that the party is over?

Get off fossil fuels.

You are right. Anything is temporary.

Also, it is not clear that continuing our motoring ways is the best use of resources.

Hi Majorian,

I'm working on a post about T. Boon's idea for CNG powered cars, and you are correct. If you power all 134 million passenger vehicles with CNG, it would overwhelm our current production. But if you use plug-in hybrid CNG cars (CNGPIH - bad acronyms strike again!), then you only need about 10% to 15% more gas after 20 to 25 years, which is not too bad (time required to replace 134 M cars at current scrapping rate of 5.8 million cars/year).

I see at least two potential problems with a only CNG-auto approach:

1) If you invest lots of $$ in a CNG vehicle infrastructure, then you've got to live with it for awhile, otherwise, you'll have to pay in $$ AND energy to build a different one. So that implies that the car of the future would be either a CNG/biofuel dual fuel model, or you go in the direction bio-CNG as a replacement for oil/gasoline. I'm not sure CNGPIH only is the way to go.

2) Natural gas is now the lifeboat of choice for many, power plant folks included. Using the EIA’s data for proposed power plants, I calculate that between now and 2015, about 6.3 TCF additional will be needed to power them plants (see my response to Gail below). When you start to add all of this on to CNG's back, it makes me nervous, especially if we don't have a clear picture of what future gas supplies will be.

However, if CNGPIH’s are part of a balanced solution and/or peak oil strikes with a vengeance before we are ready, then CNGPIH’s would be a easy way to handle part of the loss until we can find and produce bio-fuels in sufficient quantities. - SMH

I've got some stock in a little oil company that's planning on drilling two or three exploratory sub-salt wells in the later half of this year and the first part of next year in Southern Lousiana.

These wells are deep and they're extremely expensive--they're talking between $25 and $30 million each. But the reserve figures they're throwing out are jaw-dropping, something like 50 to 100 BCF per well.

Have you heard much about these plays, ROCKMAN?

Is the geophyisics used to locate these prospects new?

Is the technology used to drill through the salt new?

Isn't drilling the subsalt the same thing Petrobras has done with such stunning results?

What kind of potential could this unlock for U.S. natural gas producers?

I've heard a lot about these shale and other resource plays, but almost nothing about the sub-salt.


I'm not too knowledgeable about sub salt plays in S La. My work has been in the Deep Water GOM. But there are similar aspects. To answer your specific questions:

It's 100% seismic exploration. Even when there are a lot of offset wells (and there are very few in your play) most deep targets are confirmed seismically. Advances in seismic over the last 10 years have led these plays.

No...drilling through salt is old hat...been doing it for 30+ years. But there are still significant mechanical risks. The weight of the drilling mud is varied to deal with high reservoir pressures in all deep wells. Too heavy a MW and you'll collapse the hole. Too light a MW and you risk a blow out...makes for a very bad day. This is actually my job these days: monitor the drilling situation and make MW recommendations. The one caution: a $25 million hole can turn into a $50 million one in a blink of an eye. Drilling deep is always a risky proposition. Make sure your guys have deep enough pockets to handle such a cost overruns. My last Deep Water $100 million hole cost $148 million by the time we were done. And it was a dry hole.

Same type of animal Petrobras is chasing but otherwise no relationship.

I know Exxon and others have been chasing ultra deep targets in S La but haven’t heard of any great successes. There isn’t a potential for the cookie cutter type plays in the unconventional shale gas plays. The deep exploration programs are chasing very specific types of structural traps similar to the old conventional NG fields. There may be a number of fields to find out there but nothing like the 10’s of thousands of unconventional gas well that will be drilled. Huge payday for a company that finds one but the play won’t ever add up in aggregate like the UNG plays.

And this is why you don’t hear much about sub salt: just a few players with new discoveries coming just a few times a year at best.

Thanks for the heads up, ROCKMAN.

From what you're saying, it sounds like these are highly speculative ventures, not only from a gelogical perspective, but from an operatonal one as well.

It makes one wonder whether the potential rewards justify the risks.

These domestic oil and gas producers face some pretty tough choices. Despite all the technological advances in seismic, drilling and completion technology, a panacea of quick riches doesn't seem to be in the cards: they can either opt for the low risk-low return that the resource plays offer, or they can go for the high risk-high return projects like the subsalt.

It's a hard business.

Joe Stiglitz has a new column out today. Even though I disagree with his conclusions, I nevertheless think his division of the economy into two parts--manufacturing vs. service--is insightful:

Some looking at the U.S. economy's decreasing reliance on manufacturing and increasing dependence on the service sector (including financial services) have long worried that the whole thing was a house of cards. After all, aren't "hard objects"--the food we eat, the houses we live in, the cars and airplanes that we use to transport us from one place to another, the gas and oil that provides heat and energy--the "core" of the economy? And if so, shouldn't they represent a larger fraction of our national output?

The simple answer is no. We live in a knowledge economy, an information economy, an innovation economy. Because of our ideas, we can have all the food we can possibly eat--and more than we should eat--with only 2 percent of the labor force employed in agriculture.

Guys like yourself are out there doing the heavy lifting in the manufacturing sector. Meanwhile, the so-called "whiz kids" reap the huge monetary rewards in service sector endeavors like banking and finance.

Where I think Stiglitz gets it wrong is his characterization of the service economy as the "knowledge" economy, the "information" economy, the "innovation" economy. His blind spot is in thinking that guys like yourself, dedicated to the manufacturing sector, don't deploy as much knowledge, information and innovation as his fair haired boys in the service sector. The reality is that you probably deploy about 1000 times as much.

As much as I admire Stiglitz--his strident condemnations of the Iraq war and Bush's profligate and disastrous fiscal policies--I nevertheless think the time is rapidly approaching when we will see that he lives in a world of illusions, a dream world of smoke and mirrors.

I think Stiglits is right here, but only in times of great surplus.

Surplus energy, food, water, basically all resources.

However we are entering or in a period of huge forced constraints on all of the above.

So he is DEAD wrong. IMO

"His blind spot is in thinking that guys like yourself, dedicated to the manufacturing sector, don't deploy as much knowledge, information and innovation as his fair haired boys in the service sector. "

No, when someone like Stiglitz refers to the "knowledge" economy, he's including people like Rockman. Rockman is a knowledge worker, not a manual worker. That's Stiglitz's whole point - Rockman may not drag wellcasings around, but his services are essential to drilling.

Thanks for information on spacing. I was wondering how they were doing that. I had heard they were drilling laterals up to 4000 or 5000 feet. And I had heard they were drilling on 40-acre spacing. And I figured if you drill wells on 40 acre spacing with 4620 foot laterals, then the laterals are only going to be a few hundred feet apart, because a 40-acre parcel 5280 ft. long would only be 330 ft. wide. So I was intrigued, since that would mean they were figuring these wells could only drain 165 ft. from the wellbore.

I had also heard they were drilling numerous wells from a single location, like a fan, and I was also curious as to how that works.

It's all very interesting, and certainly a big change from the days when I was in the business.

It is a whole new world from when I started in 1975. Maersk is drilling hundreds of 25,000'+ laterals in the Persian Gulf developing a tite chalk gas reservoir. That was their chopper that just hit the platform and killed 7. I think one of my cohorts was killed but still waiting on confirmation.

Right now, in many of the UNG plays, operators are targeting a certain direction for the laterals based upon assumed orientation of natural fractures. Thus you might just see two wells at most drilled from a single location.

And you're right: the more we drill the more we learn. The wells probably aren't draining much more than 100' or 200' from the lateral. That's why you're starting to see 10 or 12 fracs per hole becoming more common. Essentially, only those portions of the reservoirs in direct contact will the frac will produce. That's one big reason why folks throwing around those big "in place" gas reserve numbers are misleading. That NG may be there but an whole lot will be left behind when the wells are depleted.


Excellent and thorough analysis.
It's good to see some positive results for a change.

Even if gasoline prices continue to trend higher at least we'll get a break from heating bills and potentially from rising electricity bills for a short period.

Good news.

Thanks for this. However I am not sure that we can be this optimistic. The evidence from wells producing gas from shale is that their production runs are very short. I followed up on DownSouth's comments on the Texas Railroad Commission reports, and typically you're seeing less than three years of production from a well (and this goes along with the World Oil report I quoted some time back). Production thus becomes a year-to-year thing with much greater difficulty in making longer term predictions since tapped reservoirs, and thus known production doesn't last that long.

i.e. better technology equals faster if we could combine better technology with a market system that pays for FUTURE earnings, as opposed to extrapolating CURRENT earnings into future, then maybe some of this natural gas would be marshalled...

Any change in trend needs to be studied and so thank you Gail for reviewing NCI's study and starting a discussion on whether the trend is sustainable. As a nat gas developer by trade, the increase in production has surprised me and many industry peers.

First, in reply to Heading Out, these wells will not have short lives - they just will have rapid declines to a low rate that can be sustained for decades.

Second, what is making shale plays work is the merging of two old technologies - Horizontal drilling in combination with hydraulic fracturing.

The entire natural gas industry is grappling with how profitable and wide-spread the application will be. It's a difficult call at this stage.

In the last few months, there has been a sudden shift in the data. EIA data shows that recent production is rising at the same time that the drilling of new wells is leveling off. Average daily dry gas production during the first five months of 2008 is up 8.1% over the same period in 2007. (Because 2008 is a leap year, total dry gas production has increased 8.8% for the five month period.)

One can look at many other measures as well, and see a similar pattern. The number of well feet drilled per day levels off and even drops, in late 2007 and early 2008, at the same time natural gas production increases. My interpretation of what is happening is that there has been a technological breakthrough, probably in the area of shale gas production of natural gas. Because of this breakthrough, companies are able to produce more gas, with less drilling effort.

There exists one key piece of information that belies your conviction that "there has been a technological breakthrough." And that is that the production cost of natural gas continues to go steadily upwards. Let me ask you, if there is some technological breakthrough that allows one to produce wee-jees with greater efficiency, does it make sense that the production cost would go up? Quite to the contrary, the production cost should go down. But with natual gas, that hasn't happened. Here are the figures for Chesapeake Energy, whose chairman, Aubrey McClendon, by the way, is also head of the American Clean Skies Foundation:

               Operating Costs*      Investment in
Fiscal Qtr        ($/MCF)           Property & Eqmt.**   
Q2-2003            $2.27                $ 58.86
Q2-2004            $2.60                $ 63.54
Q2-2005            $3.11                $120.80
Q2-2006            $3.90                $116.52
Q2-2007            $4.50                $154.01
Q2-2008            $4.73                $142.71

*Operating costs include production expenses, production taxes,
 G&A and DD&A

**Investment is expressed in the value of total property and
 equipment as reported on the balance sheet at the end of the quarter
 divided by the total number of MCF produced during that quarter

Of course these are all trailing costs, and maybe forward-looking costs will be much lower because of the much touted "technological breakthroughs." I might add, however, that if the stock prices of these companies heavily involved in the exploitation of resource plays are any indication, Wall Street is far from convinced.


Good points as usual. Drilling and completion cost have been escalating wildly. Operational costs not so much except for compression. Compression is the crazy aunt in the basement we don’t talk about much. Not only do the wells decline quickly, their flowing pressures drop to low to get into the transmission lines. I suspect a big chunk of their increase in ops cost is coming from compression. At that point some rather expensive (to acquire and operate) compressors are brought into the picture. Thus at the phase where production is the lowest operating expenses are the highest.

Even though technology advances are improving recovery efforts they do come at a cost. The cost of steel casing alone has more than doubled in the last year. At the moment, the UNG plays do offer an acceptable rate of return but not big (and more importantly sustainable) profits. As I mentioned elsewhere, the UNG plays have turned into something like a McDonald’s operation: you’re just making a few pennies per burger but if you sell billions of them they do add up. But the good news for the consumer is that, regardless of the relatively low profitability, they still benefit from increased supplies.

A small bit of the operating cost increase is due to higher amounts of production taxes collected. They are relatively small (3% to 5%) and if NG runs up $5 then that adds about $.20 to the cost side. As far as the other factors they offer it’s a mystery to me as most SEC defined numbers are.

As you say, it would be nice to see the forward looking cost vs. return numbers of well drilled 4 years ago compared to expectations for wells drilled today but that won’t happen. Closely guarded secrets well above my pay grade. I also noticed the Chesapeake presence in the ACSF. As usual, I’m always skeptical of numbers coming from the corporate cheer leading squad. I’ve seen first hand how my technical analysis has been massaged by TPTB. And don’t tell Aubrey I told you, but I would bet he would keep slamming UNG wells down even if he were loosing a few pennies on every dollar invested. At least for a while anyway.

Good points as usual. Drilling and completion cost have been escalating wildly. Operational costs not so much except for compression. Compression is the crazy aunt in the basement we don’t talk about much. Not only do the wells decline quickly, their flowing pressures drop to low to get into the transmission lines. I suspect a big chunk of their increase in ops cost is coming from compression. At that point some rather expensive (to acquire and operate) compressors are brought into the picture. Thus at the phase where production is the lowest operating expenses are the highest.

You're not kidding. Getting compression in unconventional plays is like chasing your tail. Its very easy to overspend on compression as you are trying to increase production because you're getting all these gangbuster wells and management is screaming "We're losing production, we need more capacity", but then the wells' decline is so steep that within weeks of not hitting another giant producer, you're way over capacity on compression and management is screaming "OMG, why did we place orders for 3 compressors" (because leadtime is such that when you want the compressors, they're 6 months to a year out). Then, before you know it, drilling has moved on and you've got the albatross of oversized overheating compressors and they're draining your bank. Tight gas is horrible on facilities planning.

Never a dull moment in the oil & gas patch.

In support of some of your comments, it seems to me that UNG operators are going to keep drilling almost no matter what the price is, primarily because of lease situation. If you have a large block that you paid a few hundred dollars for, but that might cost you tens of thousands of dollars to renew (although this could change), you are probably going to drill. And if you have a short term lease that cost you tens of thousands of dollars, you are probably going to drill.

All in all, it could make for some interesting times price wise. I have concluded that I am glad that most of my production is oil.

Growth is going to be a big issue in stock company valuations. Highly leveraged companies like Chesapeake Energy are going to have a hard time keeping up their growth, with the problems in the credit markets. The low current valuation of natural gas isn't doing them any good either.

The reason I am not as worried as I might be about the operating costs going up is that oil and gas are closely connected, and oil prices have been rising rapidly over the last several years. As the price of oil goes up, so does the price that consumers are willing to pay for natural gas (Especially if the American Clean Skies Foundation is successful in getting people to use natural gas powered cars. More on that in my next post.)

Are operating costs usually the same per field /well? If the average cost is approaching $5 there may be some wells below that and others above that #. I could see some well with operating costs of $6.50 or more that would be shut in if prices go below that level for an expected period of time, not just a day or two.

From various notes from brokerage firms, the marginal MCF in US is between $6.5-$7.00. That means the last few hundred BCF that are produced (out of over 21TCF) cost around $7. This will likely continue to escalate at a higher rate than in the past, due to the quick depletion using horizontal technology. So there WILL be a burst of new gas in 09-10, but how long it lasts will be another question.

Average cost per MCF on high quality Haynesville shale property is about $1 per mcf (almost all up front in the drilling). Coal bed methane in Rockies might be closer to $5 per mcf. All of this is usually reflected in companies share prices that are represented in various areas.

In sum, as the marginal MCF cost increases, only the cheapest to produce areas are going to be very profitable. From this point forward, I expect the commodity itself to outperform the majority of NG companies (there will be a few that crush it however...)


It will tend to vary more by "field" then by well. But even the term field is misleading. It's really more representative to say each well is a field unto itself. Unless you drill too close each well will be producing its own unique portion of the reservoir. The producing areas, from an operating cost stand point, are defined by lease ownership and not geology. Chesapeake, for example, owns 100’s of thousand of acres in E TX and N La. But those acres may be broken up into something like 300 different contiguous parcels. Each parcel, containing many wells each, would function as a separate “field” from an operating cost stand point. An older parcel, with big compressors on it, would have a much higher operating cost then a newly drilled parcel. Some parcels with the same number of wells may have total rates significantly different than others. Individual wells on a parcel may vary significantly in production rate. In those cases operating cost are usually assigned on a pro rated basis. This is actually a very complicated accounting problem as royalty ownership typically varies from well to well.

The best non-engineering analogy I can offer is to imagine an apple orchard covering half of Texas. Each tree represents one unconventional NG well. There will be some trees with lots of nice apples and some with almost none. And you might find your best tree next to one eaten up by bugs. But you know you can drive 500 miles north and still be in the middle of an apple orchard. But is that section full of good trees or bad trees? Don’t know till you get there and start picking (or drill a well). This is why I think it’s a little misleading to start predicting recovery numbers from areas where, although they may contain the same UNG reservoirs producing elsewhere, little or no drilling has occurred yet. Just like everything else in life, there are sweet spots out there amongst the sour ones.

I will add that even if a well is only making $1 profit PER MONTH, most operators will keep it producing regardless of how poor the operating cost to net income appears. It costs thousand of $'s to abandon a well. Additionally, the operator continues ownership of the lease. Abandon the well and the lease usually expires in 30 days. Many of the UNG wells being drilled today are on leases that have been maintained in just this manner for many, many years. There are leases being drilled that would cost $20,000 per acre today that companies paid $30/acre 20 years ago. Many lease contracts even allow an operator to pay a “minimum shut-in royalty” for wells that are producing nothing just so they can maintain ownership.

It costs thousand of $s to abandon a well.

Is this due to unavoidable technical limits (underground flow dynamics?) or "only" to above-ground reasons (legal and financial transactions etc.)?
In the latter case it might be possible to streamline such processes in order to allow more flexibility.

I was very interested to read that in Utah they cannot keep up with demand to convert cars from gasoline to NG. The reason is that the NG to gasoline equiv is 87 cents per gallon, where gasoline is selling for 3.75

So if you drive 20,000 miles a year the conversion cost payback is about one year. after that you are paying 87 cents a gallon

Honda is the only company selling a true NG powered car - the GX - and the backlog is 8 months

If the excess NG supply Gail discusses continues, the gasoline/NG price ratio will only improve

people will vote with their wallets


I don't know for sure about Utah but I recall last summer an engineer working the rockies told me NG fell to less than $1/mcf at the well head. The NG transport lines had hit capaity and you either sold at the low price or you shut your well in and made no income. New lines are being built to markets back east as well as the west coast. I'm guessing that future NG prices for you will hang on this transportation issue.

I can verify that. I saw a production nomination price at $0.10/mcf during the worst period.

And I bet the gas buyer made the producer pay for lunch too.

I take that back, it was a spot price. Unfortunately with no capacity in the transport lines, it was the best that could be gotten in the local market.

some cbm gas in the wyoming powder river basin sold for $0.12/mmbtu in nov '07. rockies gas has historically been a step child due to distance from markets and lack of pipeline capacity.
in '07 there was a fire at a major compressor station near cheyenne, wyo that handicapped the market even more. since then that facility is back in operation and additional pipeline capacity has been added, rockies express i think it is called.
the same wyoming cbm gas sold for over $9/mmbtu in june '08.

I looked at, and most filling stations in California are $2.50-$3.00/gge with a few closer to $2.00. It's really shocking how cheap it is in Utah and how much it varies by state. TX is $3.00/gge; OK is $1.00/gge. If you fill up at home, the utility rates for gas are much cheaper than the filling stations, but when you consider the cost and service life of a home refueling unit, you'll pay just as much.

Since "peak" storage is only needed about two months of the year, there is little incentive to develop new storage until a larger peak storage is needed.

Thanks for a great article, Gail - but then that is no more than we are accustomed to from you.

In the context of the discussions here it might also be worth mentioning underground coal gasification, as by that means a lot of what would otherwise be inaccessible deposits may be used.
The links I have are for Europe, but resources are also very large in America, one would imagine:
Energy Balance: Underground Coal Gasification.

I have read about this also, particularly in reference to China, since they have such a need for more energy resources. One report that talks about this is "Coal of the Future", a study by B. Kavalov of the Institute for Energy (IFE), prepared for European Commission Joint Research Centre. I haven't been able to find a working link for the study. This is a quote I copied from the report, when it was on line:

China has probably the lead market for UCG, and the greatest incentive, with few alternatives to meet its power and liquid hydrocarbon requirements. It is also well ahead already in establishing a technology base for UCG, although State intervention could help or hinder its development.

To date construction of in-seam gasifiers in China involves the use of underground mining methods. The Chinese UCG work has involved some 16 trials in shallow coal in various mining companies, and the programme is supported by the Centre for Underground Mining and Technology (CUMT), which has extensive laboratory facilities, including a 4m long test chamber for the simulation of underground tests. Not much is known about the success of the programme, apart from a few test results.

The State oil company, Petrochina is starting a deep-seam UCG field trial leading to commercial production in Liaoning Province, North East China. Seismic surveying and drilling for oil had identified a thick seam of deep lignite, which might be suitable for the UCG trial.

Here is a link to a brief article on China's progress in simplifying underground gasification:
China simplifies method for turning coal to gas - tech - 18 July 2007 - New Scientist Tech

And here is a link to another gasification company:
.:: ERGO EXERGY TECHNOLOGIES, INC. - The only source for Underground Coal Gasification ::.

And here is a coal gas to liquid fuel project:
Gas to Liquids GTL - Underground Coal Gasification UCG - Linc Energy - Fueling Our Future

The major reasons I could see to add more storage:

1. Trying to bring more folks to NG residential heat, particularly in NE.

2. Problem with year to year maximum heat need, if unusually cold winters.

The problem of exceeding storage capacity would only be a reason for building storage more if it could be cost-justified, based on evening out the price variability. I am not sure it would help much--storing more would probably just delay the problem of too much supply for a few months.


There is actually some salt dome NG storage outside of Houston that handles just the DAILY float of NG gas and not for seasonal demand swings. Between the power plants and residential users there is a big swing in daily demand…enough to justify this sort of operation. Your comments made me wonder about the prospect for similar complications should other major metropolitan areas start a significant switch to NG. Even if there were sufficient seasonal NG storage could NG suppliers to NYC handle daily swing volumes without a local storage system? New potential solutions also bring new potential problems with them.

I just don’t understand why things are getting so complicated just because we’re getting closer to PO.

I worry that we someone will start converting cars to natural gas use on a big scale in someplace where natural gas resources are stretched to begin with, like Boston. It seems like this could play havoc with supplies. If the cars are mostly used for commuting, use could be very different on M-F than weekends.

Some of these technology improvements seem to have some analog in the oil extraction area - I'm thinking specifically of the THAI process for extracting tar sands oil. Does it not seem possible, even likely, that in the next 10 years or so, improvements in our ability to extract oil from poor quality areas (like tar sands) that have huge quantities of oil will improve to the point where we can sustain production levels at 50, 60 or more million barrels/day worldwide for the next 50 years or so?

This is a process which is supposed to increase oil production:
'Modified Seawater as EOR Fluid Could Boost Oil Recovery From Limestone Reservoirs Up to 60%'

I have no idea how realistic this is, or if people like west texas have taken it into account in their projections.


I can't give details because I'm bound by a confidentiality agreement. But this is real. Statoil in Norway has more. is a good starting point.

Thanks for the info.
I don't know if you can comment on this, or perhaps others could given your assurance that it works - how much difference is this going to make to projections given here for oil production?

Is this a major difference, or is it already accounted for as technical progress which was held to be probable?

What does this do for peak oil, and decline rates?

Enquiring minds want to know! ;-)

The next time Fractional Flow or one of the other engineers stops by, you might ask them, but in general terms I think that incremental increases in oil recovery factors won't have a material impact on the big picture, but as I said, see what some of the engineers have to say.

Just on a naive reading of the link I gave, they state that around 50% of reserves are chalk or limestone, that recovery in chalk could be up to 40-60% higher, and that chalk has a more reactive surface than limestone, but that they have got around a 15% improvement from the limestone.
On the assumption that the split between chalk and limestone reserves is 50-50, then you might be looking at an average of 30% better recovery form 50% of fields, so it would come out to something like 15% of total reserves.

Not enough to delay peak forever, but not to be sneezed at either, especially coming at this stage in the game, and if that is in the ball-park could do a lot to cushion the decline.

the process of imbibition of water into the pore space, especially small pores , is an important component of any water displacement process. this occurs at a low rate (not suitable for pw economic forecasts). imbibition is very efficient , water enters the pore space, displaces the oil and doesn't increase water relative permeability, because of the rocks affinity for water. imbibition is limited to a few % of pore volume.
alkaline flooding and its cousin alkaline surfactant polymer flooding has been used in the us and canada since at least 1986 that i know of personally.
displacement by imbibition is not new in the north sea either particularly in chalk reservoirs, going back to about the same era.

arps discussed this in some of his work done in the '50's and this along with gravity segregation is long forgotten oil field lore.

in short, i dont think it will sell in this pw economic, maximum production, next quarterly report enviromnent we are in.

I can't find any relevant news there. But there's the story titled "Free ferry trips for el-powered cars" - maybe this is a good hint to the real solution ;-)

I can't find any relevant news there. But there's the story titled "Free ferry trips for el-powered cars" - maybe this is a good hint to the real solution ;-)

Probably the statement "Upcoming experiments will verify" is the key message in this article. I can't help to find that "Modified Seawater" sounds a bit esotheric to me: It would be a huge surprise if after decades of expensive and extensive R&D such a simple method would boost the recovery rate.
Using sulfuric acid in the underground is already a standard leach&pump method at uranium mining (and the precipitation of BaSO4 a possible means to clog the porespace).

I think that there is some possibility there. We even have some very heavy oil deposits in the US. (I have heard Texas and California mentioned.)

I think that there is probably a long list of obstacles for these sources as well, perhaps somewhat analogous to my list of obstacles at the end of this article for unconventional gas.

All of the obstacles you mention seem solvable or are obstacles from the market-based economy, which means that when we get to the bottom line, there is gas that can be produced. This gives me hope. It makes me think that Ilargi is right - that what we are facing is economic collapse, maybe societal collapse, but not civilizational collapse. Hopefully the difference is clear without me having to define these terms :-)

I admit to being pretty dense, so maybe you can help me. At least to the individual, a societal collapse would look a lot like a civilizational collapse, I believe.

Do you, or Illargi, mean that the "civilization" the Ancient Greeks started (more or less) has remained intact for 3000 years, despite the short term collapses of the Roman society, the Holy Roman Empire, medieval Europe, etc.?

In the end, what are we trying to preserve? What is the basis for your hope? Many of us would be happy to give up those parts of the current society that we feel are harmful or useless in exchange for those parts which are worth preserving-- especially if we didn't personally perish in the process. And in truth, it probably wouldn't take a lot of oil or gas to accomplish that. But we are all so fearful of change that we will hang on to our familiar unsustainability as long as possible. Me included, no doubt.

I probably shouldn't speak for Illargi - I was just saying that I think he's right when he says our problem is primarily financial and not a matter of demand wildly outstripping a dwindling supply, and that the price of oil will go lower, but you still won't have the money to pay for it. Neither of us have any argument with the peak oil theories other than how it's going to play out in terms of price.

Beyond that, I would say:
economic collapse = Great Depression
Societal Collapse = End of Soviet Union
Civilizational Collapse = Olduvai Gorge

If you combine economic collapse and societal collapse, you get what I am expecting. There will be a lot of pain, a lot of violence and crime, some war, famine. But, our knowledge we have gained in science in technology will mostly survive, and there will be means available for the survivors to pick up the pieces and start over again at a pretty decent standard of living. And the death toll will be in the millions rather than billions.

I'm such an optimist, don't you think ;-) ?

I don't know anything about optimism, and couldn't judge your depth of feeling.

I'm more of the Walter Miller line of thought

Listen, are we helpless? Are we doomed to do it again and again and again? Have we no choice but to play the Phoenix, in an unending sequence of rise and fall? Assyria, Babylon, Egypt, Greece, Carthage, Rome, the Empires of Charlemagne and the Turk. Ground to dust and plowed with salt. Spain, France, Britain, America — burned into the oblivion of the centuries. And again and again and again. Are we doomed to it, Lord, chained to the pendulum of our own mad clockwork, helpless to halt its swing?

Today, I feel like Illargi is practically a stand-up comic.

Speaking to the demand side of the equation, and also framing it in a larger political context, here's what Pickens and McClendon are up to:

(There was another excellent story linked from the Drumbeat the other day on this same subject, but I can't find it.)

They want natural gas transitioned as a transport fuel, and they want tax-payer subsidies to pay for that transition.

I'm 100% in favor of the use of natural gas as a transport fuel. On a heat content basis, it's a real bargain in comparison to oil, and also much cleaner burning.

But I question the need for tax-payer subsidies. I have some problems with that, especially when they're being promoted by these right-wing, so-called free market fundamentalists (the hypocrisy is mind boggling), and also question whether they should be necessary if everything is as they claim it is.

I think transportation use of natural gas will be very difficult to control. It is very difficult to see a need for tax-payer subsidies. I will write more about that in the next few days.

I agree with you DS. The tax payers will be supporting NG vehicle fuel enough just by having to pay for conversions/new vehicles. But T. Boone is great at this game. I'm sure you know about his wind farms in W TX. Do you know that there is no market for his product out there? That's why it was so cheap and easy: no competition. But unprofitable too. No problem: a couple of months ago the TX PUC approved a $2.4 BILLION transmission line, at rate payers expense of course, to connect his wind farms to Dallas. Easy to guess that his wind farm is now worth many, many times its value of just a few months ago. It's great to have powerful friends in Austin....makes you look like a real savvy business man.

Don't forget his purchase of the water rights from the Ogewalla reservior to sell to Dallasians also

No, ROCKMAN, I hadn't heard that. From what I had read here on TOD the plan was to get power of eminent domain from the state for his power transmission and then use the same right-of-way to build a pipeline to move his water to market.

Like I've said before, he's one ruthless SOB. But to be honest with you I don't find that all that objectionable. What bothers me is the layer upon layer upon layer of hypocrysy.


I feel that the profit margins for the production of these unconventional sources will be squeezed from both the top and bottom. Enhanced horizontal drilling will decrease EROI thereby increasing production costs, while increasing supply (production levels) above and outside the market elasticity (nearly inelastic market) of NG will lower prices, therefore decreasing further the profit from these developments. Although i am not sure this squeeze will be enough to thwart production....Anyway - Good post

I think that is why folks are really interested in ways to ramp up demand quickly, and get the price up. More on that in my next post.

Nice overview of the situation, and helpful to have the charts. I'm not sure that we have to choose however, in our current analysis, between technological breakthroughs in drilling, and, data errors, or the persistent sense that EROEI decline is underway. My view is that we have both. The technological breakthroughs in drilling for Shale NG are real. They are real in the sense that we can both tap the resource that was previously uneconomic, and, that the drilling techniques themselves are being perfected over time. Producers learned how to do it, and now they are getting good at doing it. However, any declines or efficiencies in the new drilling techniques are coming off of much higher levels. They are coming off of the original step-change higher, in the costs to drill via the new method. Eventually, the new method will no longer be seen as new. It will be perfected to the degree that drillers new to the game will be able to uptake the skills. However, the new method remains very energy intensive. The water required is intense. The diesel required to run these rigs is notable. And the specialized metals/pipe to do this are expensive. I can't, offer up more quantitative data on that however, as I only understand the situation thematically, at this point. I think we are still in the early stages of analysis where we are rooting around between Rig Count data, actual reported cost figures from the Producers, and some hype and even strong disagreement on these issues within the industry itself.

What's an easier lay up, however, is that while the continental US has indeed found a way to increase NG production (again, at a higher price, imo), what's pretty clear is that Canada is not there yet. And the import/export data from both EIA Washington and Statistics Canada , on Canada's growing needs and reduced ability to produce NG are notable. For the moment, it looks to me like the lower 48 will be able to offer NG to both Mexico and Canada, via the expanded pipeline export capacity built out, over the past decade.

Between 1990 and 2007, import pipeline capacity from Canada increased by 169 percent (to 17.3 Bcf per day) and from Mexico by 147 percent (to 0.9 Bcf per day). During the same period, export capacity to Canada more than tripled (to 4.3 Bcf per day) while export capacity to Mexico quadrupled (to 3.6 Bcf per day).

I do agree that the US needs to increase storage capacity. Significantly. Especially if we are to move to CNG, say, for government and state vehicles. But it does seem to me that, even though we have no LNG export capacity in the lower 48 (we do have Alaska LNG run by Marathon Oil) that Mexico and especially Canada will need our NG. Based on current trends.


Here's some more info from the Canadian Assn. of Petroleum Producers:

In addition to natural gas and oil production it also gives some data on drilling activity and costs going all the way back to FY2000.

I agree that reduced imports from Canada and increased exports to Canada/Mexico are likely. These may reduce the amount of additional gas that is available to US consumer by 40% (or even more), depending on the assumptions made.

I started to try to write about these issues in this post as as, but decided I couldn't cover everything at once.


I can see export potential to Canada especially if you throw ramped up tar sand production into the mix. But with regards to Mexico how would you project their ability to pay for it? As their oil production continues to drop their imports demand will certainly increase but at the same time their falling oil income will make it that much more difficult to pay the rate. This is why I see the potential of the worst case doomer views of the future for Mexico.

I could see someone opening up a fertilizer factory in factory, or something similar, and using the sales price of the output to pay for the NG input. But you have a good point--poorer people will find it more difficult to purchase anything. That goes in the US as well as Mexico.

Gail, I always enjoy the excellent quality of your posts and this one is no exception.

I do, however, have a very different perspective on the interpretation of import/export numbers. Decreased exports of Canadian NG to the US have most likely been caused by competition from increased American production. There are no projected NG supply problems here that I am aware of.

A couple of months ago the CEO of Encana was interviewed on local TV. He was talking about potentially 100 Tcf from their first Horn River development with another 100 Tcf from a second development nearby. Some estimates are even higher:

Total gas-in-place estimates in this piece of the Horn River Basin range to as high as 600 trillion cubic feet.

Horn River

NG developers in BC and Alberta see the following conditions:

  • potential competition in eastern Canadian markets from UNG in the St. Lawrence valley
  • competition in northern US from UNG in Pennsylvania, western NY state, and elsewhere
  • increased competition in eastern seabord markets from Texas
  • a possible pipeline bringing lower cost gas from Alaska

It's not at all certain that increased UNG production from BC and Alberta can be sold at an acceptable profit. Which is a very different situation from not being able to increase production.

One additional point that I would like to make.

There is a legitimate argument to be made that oilsands production (using current methods) will be limited by availability of NG. In one of your posts, you seem to believe that UNG production will be limited by the availablity of oil. However, IMHO, if the NG is available, then there should be no difficulty in oilsands production for the forseeable future.

I wasn't really looking much at the Canadian end of things in this post. Long-term, I was expecting Canadian exports to the US would decrease because of greater use of NG for producing oil from the oil sands. I believe there may also be some royalty issues also. If our production is cheaper, that may make a difference as well.

AFIK, longer term (> 10 years) energy for oilsands extraction will mainly come from geothermal and nuclear. NG is projected to be too expensive.

I thought both of them were quite location dependent. You put your nuclear reactor in one location, and do your mining around it. If 20 years out, you have moved too far away from the reactor, it doesn't work any more, and you have an expensive, no longer necessary reactor. Or do you convert the energy to electricity, run wires to where you need it, and use electricity to heat the oil sands?

The nuclear reactors would be used for electricity, not for heating. Geothermal is location-dependent in the sense that different locations will require different well depths - so it is a cost issue.

My company estimates about a decade before widespread use of next generation energy sources. There is a lot of work to be done to get reliable cost estimates for different configurations.

One of the big drivers is the expectation of increasingly stringent limits on CO2 emissions.

Although this excellent study focuses on supply I would be interested in the demand side analysis as well. Of course much harder to predict and forecast. But with the PickensPlan and others pushing for NG as the bridge for transportation until we come up with the next great idea for some sort of renewable transportation. I would be interested to see how this all plays long could NG be a bridge before we suck it all up for our transportation needs. I think I have heard Pickens throw out the 2030 date for the bridge window.

I started to try to put both supply and demand discussion into one post, but the post got totally unwieldy and too long to read in one sitting. I will try to attack the demand issue in another post.

Natgas demand is actually fairly flexible in the mid-term. I don't think the scenario of strong increase in natgas demand is that unlikely - NW-Europe went through the exact same experience, four decades earlier: the unexpected discovery of lots of local natgas. A fine mesh of pipelines has delivered natgas to retail customers, which has almost completely eliminated heating oil usage outside of remote/mountainous areas. This transition started in the 60s and was completed in the early 80s, with heavy industry (steel mills, power plants) the last to give up burning fuel oil. If that transition could be done with 1960s technology, it can certainly be done today.

With the North Sea fields in decline, this will probably lead to a shift for LNG: the major flows will divert to Europe rather than the US.

I think the heavily populated NorthEast is the only part of the US that didn't get converted to NG years ago. Pipeline capacity there seems to be low. I suspect with the dense population (making upgrades to piping more difficult), and being the most remote from the source, it got left until last.

Since Sarah Palin has made her debut I, and the entire nation I suppose, have become intrigued by the proposed natural gas pipeline from Alaska to the Lower 48.

To me this is a potentially much better recipient of tax-payer funds than the Pickens/McClendon Proposition 10 being considered in California. Wouldn't the benefits be much more evenly distributed to all Americans instead of the handful who would benefit by buying a CNG vehicle?

I don't see why the federal government can't build that pipeline. In Texas we have all these farm-to-market roads that originally were built so farmers could get their produce to market. Wouldn't that pipeline be in that same spirit? One difference is that the government could charge a transportation fee.

Drumbeat had a link the other day with some of the details:

According to the article, Alaska has 35 TCF of proven natural gas reserves and an additonal 250 TCF economically recoverable. I think someone needs to verify these numbers, as Palin, not unlike most of those who inhabit the Beltway these days, has pretty well squandered her credibility with rash statements like her 11-billion-barrels-of-oil-and-9-TCF-of-natural-gas-under-2000-acres claim.

My concerns with the pipeline are two-fold:

► I don't see how it can be economically feasible without some sort of government subsidy. It is projected to cost $30 billion and will carry 4 BCFPD. Figuring straight-line depreciation over 20 years and 10% annual ROI you're already looking at over $3.00 for each MCF that you put down the thing, and that doesn't even include direct operating expenses. I am cluesless as to what operating costs might be, but let's make a wild guess of $0.50 per MCF. So at today's Henry Hub natural gas price of only $7.00/MCF, that means the Alaskan producers of natural gas net only $3.50 per MCF they deliver to the intake of the pipeline.

► Whoever builds the pipeline will have a de facto monopoly on buying and transporting natural gas produced in Alaska to market. If government subsidies, eminent domain and other quasi-governmental concessions are awarded, then it only makes sense that the pipeline should be treated like a public utility, accessible to all current and future natural gas producers on the same prices and terms, those prices and terms governed by a state or federal agency. If the deal Palin has cut with TransCanada does not do this, then she is awarding it a liscense to steal. My question is this: Wouldn't it be easier just to have the federal government be the owner?

Once the pipeline is in place, open up to the state to competitive oil and natural gas leasing and let a thousand flowers bloom. And if her claims that the incumbent producers are sitting on and refusing to develop all these potentially prolific leases are true (claims, by the way, that I find highly dubious), then I see nothing wrong with her proposal to use the full extent of the law to force those producers to either drill them or relenquish them to other operators who will.

I would go along with the gov't ownership of the pipeline but only if Down South were appointed the Pipeline Czar. I can think of many major energy projects that would, theoretically, be better managed by such a central control. Unfortunately, I just can't see our current political structure being up to the task. I really am ashamed to say it, but I would rather see Petrobras pay for and manage the PL then see the US gov't get involved. Honestly.

Ha! Ha!

I can just create my own little country 1600 miles long and 100 ft wide, apply for a foreign aid package from the U.S. to build my pipeline, appoint myself dictator and rake in the bucks.

I could name it DownSouthistan, and every time the President of the United States made me mad I could threaten to cut off the gas.

Once you start getting into subsidies, I think you run a real danger disguising a situation where you are converting 1.5 million Btus of oil energy to 1.0 million Btus of natural gas energy. If a project doesn't make sense on an unsubsidized basis, there is a good chance it doesn't make sense period.

You will notice I commented on EIA's forecast of 2 trillion cubic feet of natural gas from the Alaska pipeline, starting in 2020, up near Figure 5. The pipeline would need to carry about 5.5 billion cubic feet per day to meet this target. If the US resources are as good as NCI seems to think they are, the amount this 5.5 billion cubic feet a day adds to our projected supply at 2020 is only on the order of 7%. If the pipeline is smaller, then we are talking adding 5%. How much should we be willing to spend on this incremental supply?

Appears Shell Oil has bought into the potential way up north. Just saw the press release: they paid $2.4 billion for around 275 offshore North Slope tracks. That's a bit of change for one company in one lease sale...even for Shell.

I see from a link on today's (Sept 5) Drumbeat that Palin has upped the ante to build the pipeline:

Palin's speech was the first time a $40 billion price tag had been floated. TransCanada has pegged the cost at $26 billion and state consultants have estimated $31 billion.

So does that make the cost $4.00 per MCF plus operating costs, just to pipe the NG to the US? If NG is selling for $25 per MCF, this might work, but I suspect other costs would be higher then also.

I don't know Gail, I'm not an accountant nor a pipeline financier, so I don't know exactly how returns are calculated on pipeline projects nor what sort of return on capital the people who invest in these projects look for. Likewise I'm clueless as to what direct operating costs might be.

Certainly, many factors could affect the "cost." For instance, if the builders of the pipeline are able to finance the project with tax-free bonds that would bring the cost way down. Likewise, if the loans are guaranteed by the government that would bring the cost down. There are many ways to subsidize a project like this, passing costs and risks onto the tax-payers without appearing to do so.

But the wild guestimates I made were to demonstrate that bringing that gas down to the Lower 48 will be an expensive proposition. And as this discussion has highlighted, there are a lot of new developments on the natural gas front that make predicting natural gas prices just a little bit dicey at this point. I just don't see how, given everything that's going on right now, and until the dust settles a little, that this pipeline could possilbly be built without some government subsidies and/or guarantees to at least ameliorate some of the downside risk.

There's another article in this morning's Dallas Morning News about the pipelie:

It says its projected to carry 5 BCFPD.

Here's an interesting quote from the story which serves to strengthen my contention that, whether the pipeline costs $30 billion or $40 billion or whether it carries 4 BCFPD or 5 BCFPD, it won't be built without significant tax-payer subisides:

Since taking office less than two years ago, Ms. Palin has increased tax rates on current oil production, pushed through the Alaska Gasline Inducement Act, which authorized a $500 million subsidy for TransCanada...

It looks like there's a lot of smoke and mirrors going on here. I'm not sure this is the chiliastic showdown between big oil and the people of Alaska that Palin is portraying it to be. Maybe it's more of a battle between powerful interests within the oil and gas industry.

There are also some links from the Dallas Morning News story to some web pages that discuss some of the issues which I have already raised.

Gail's excellent item prompts me to ask how much of this resource exists globally and what is its distribution?

I haven't looked into this. If I were in Europe, and depending on Russia for my gas supply, I certainly would start looking at whether there was any local gas production I could ramp up.

Your comment about Europe is timely, but I was thinking more about Asia, particularly India, Japan and Pakistan, and also the many energy deficient African nations.

It seems like they should be looking at what is available locally also.

The US may have more than its share, because it also has oil and coal. It may be that variations on the same conditions cause all three, but I really don't know about this.

As far as I know save for coal bed methane maybe, Europe has almost none, outside Russia anyway.
There are some shale deposits in Scotland and Lithuania, if they are associated with this unconventional gas, but nothing remotely comparable to in the US

poland is developing nat gas supplies, some from the rotligand (sp?) of gronegan fame. i have heard though that this in cbm gas also that happens to be trapped in a sandstone reservoir.

poland has a long way to go to provide for their own needs.

Actually organic shales is one of the most common rock types on the planet. But this doesn't mean all could be exploited for NG or oil. One example, I believe, is Jordan. They have huge deposits that the Russians, Chinese or Iranians are negotiating a deal over.

I agree with Pickens that natural gas is the transport fuel of the future. Too much effort and anxiety will be needed in maintaining production of room temperature liquids of various kinds. Natural gas for vehicles is clunky but low stress. Some don't see the logic of taking gas away from electrical generation, particularly baseload, if the price is affordable. I would argue that we need the versatility of gas for the long term and other ways are available for generating baseload. Perhaps that justifies a mandated quota system ie no more than a fixed percentage of gas can be used for electrical generation.

Looking decades ahead I wonder if we should try injecting and blending biomethane and biosyngas into the natural gas network. That would require similar heating value gases with low tar and low fire retardants N2 and CO2. The inert gas content probably rules out using UCG gas formed by partial combustion. When natural gas fully depletes the network will still be there so it should be used. Particularly if there has been a major investment in depot or home refuelling.

Incidentally a major problem emerging with coal seam methane in Australia is disposing of saline water in areas with good rainfall. Right now a lot of it goes into evaporation ponds until they overflow.

It seems like it would be more efficient to burn the biomethane and biosyngas locally, in power plants that had been specially tuned to take their fuel. Or is there a way to make some plants so that they can use a range of fuel stocks? This would save a lot of extra treatment and transportation.

In some places in Europe they feed the biogas into the system:
Biogas Flows Through Germany's Grid Big Time

Apparently care needs to be taken to ensure that the gas is of the correct specification to go into the same system as natural gas.


The electrical grid has quality standards for voltage, frequency and harmonics +/- some leeway though I can see some advantages in an unregulated grid filtered by the user. Any input to a 'universal' gas network would most likely have to be around 80% methane. Apart from heating value and comparable Wobbe index some nasties like sulphur compounds would have to be excluded.

Really I have no idea whether renewable gas can ever replace natgas on large scale. Localised applications may indeed be best.

I wonder if we should try injecting and blending biomethane [...] into the natural gas network.

Here's proceedings that describe the present state of biomethane in Europe, as well as the upgrading techniques. Text is in German (15MB), with English translation of the introduction: Biogasaufbereitung zu Biomethan / Biogas Upgrading to Biomethane.

Searching for biomethane yields further wealth to ponder; among which:
Biomethane presented as most efficient biofuel at NAAC Conference.
Report: biogas can replace all EU natural gas imports.

Germans just enacted legislative framework that incorporates biomethane into their feed-in tariff system. Self-sufficiency though still seems a long shot.


Speaking of technological breakthroughs, the Energiepark Bürstadt claims to have increased the efficiency of methane output from feedstock by over 50% while dividing the duration time of fermentation (90 days for maize or grass) by 10 by means of up front thermal hydrolysis. Normally this is achieved as the first step of the fermentation process.

From these sources I concur that this would bring cost down to the low side of the 10-20 euro range per million BTU for large installations, assuming normal feedstock prices and barring prohibitive expense for the hydrolysis unit.


Just a copy of a post I put on the drumbeat--I thought this was a more fitting article to have this discussion:
Although most people seem fixated on the price of oil, I've recently become more interested in the long term outlook for nat gas.

On the demand side, the bullish aspects include (1) increasing demand for electrical production due to inevitable carbon tax/cap and trade (both Obama and McCain support cap and trade+dem congress=cap and trade) increasing the price of coal PPs) (2) increasing home heating (oil-->nat gas conversions reportedly up ~50%), (3) oil sands ramp up, and (4) ramping up of wind (more wind=more intermitancy=more natural gas requirements)

The bearish aspects of demand are that (1) solar produces mostly peak power, reducing natural gas peaking production, (2) expanding EV usage will increase baseload power, and (3) a smart grid would both increase baseload demand and decrease peak load demand.

On the supply side, while the relative success of the unconventional fields has brightened the supply picture in the lower 48, it's still far from good in the long term. Plus, if demand goes up to the point where we need to rely on LNG imports (which almost certainly will happen), LNG prices are just about the same as the price of crude.

Overall, it seems to me that the price of natural gas will likely skyrocket in the mid to long term. Any thoughts?

My next post (on demand) will talk more about the price of natural gas. I expect it will rise to closer to parity with oil, if it is used as a transportation fuel. So I guess I agree with you that it may skyrocket.

I am not nearly as optimistic as you are about electric powered vehicles. I think there are just too many obstacles in the way. Natural gas powered vehicles are used in many places in the world, so the technology is already available. Electric cars are still a ways away, and it is not clear the technology will scale up well. Also, I am not convince the grid issues will be easy to overcome.

Personally, I think it's a terrible idea to use natural gas as a transportation fuel. Natural gas is a vital resource for electricity, home heating, industry, etc, and I fear that if we ramp up demand by using it as a major transportation fuel, we might have to start importing large amounts of LNG, meaning we pay the world price, which is almost at parity with crude.

The US is unlikely to be importing large quantities of LNG, as for a start it is a heck of a lot more expensive than the US is used to paying for gas, and secondly because the supplies simply won't be there, as any increase will be bid beyond what the US will pay as they need it far more in the far east and Europe:
tehran times : LNG project delays may cut 100 million tons of supply | Business | Is LNG flame burning out?

Well if using CNG increases our natural gas demand 50% for example, where do you think that will come from? Surely some of it will have to come from LNG.

I can see bio-gas from garbage and from various crops before I can see LNG. There is not going to be very much LNG in total. We are a long ways away from where it is produced. It will always be expensive.

Also our balance of payments is in terrible shape. We do not need more expensive imported fuel, even if available.

This is somewhat off topic, but could somebody (Khebab?) please explain the anomalies on this graph to me. As an example, notice that around the beginning of 2005, The Russian production curve at the bottom is essentially smooth. Now the next one up, Brazil, has a small upward discontinuity in it's curve at the same time. Notice that the discontinuity is propagated up through each production curve, increasing in amplitude, resulting in a mighty leap for the producer at the top, Saudi Arabia. If you look around you will see many such instances. Is this real or an artifact of the spreadsheet (which I assume was used to produce the graph? If it is real, what could explain the coupling between producers?

BTW, I tried the img tags but couldn't get the graph displayed. How do you do that if you have the image's URL?

What you are looking at is one of Matt Mushalik's incremental production graphs. I talk about them some in this post. These show only the top "slice" of the production for each of these countries, all stacked together. (Look at my post for more discussion.)

The way you make a graph show is with code such as the following, but using < and >, instead of ( and ).

(img src= "URL" width= "90%")

You don't always need width= "90%", but it is good to put in if it is a big graph, and exceeds the width of the screen. You can also use a different percentage, like "80%" . Use preview to test to see what it looks like.

Gail, thanks for the tip on graphing. Unfortunately, I still don't have an answer to my main question. Are you implying that these growing anomalies are part of the process for making an incremental graph? If so, the results are misleading at best.

I look down the list of countries to find which one is causing the anomaly but it looks like they all are except the lowest one. How much seems to depend on its position on the graph.

Matt has layered together the "tops" of different production curves to try to show graphically which countries are adding to production, which are declining in production, and which are bouncing around.

In this particular graph, he has used various shades of green for growing countries, and they are on the bottom.

He then has several layers of countries that were increasing, but either recently or longer ago started to decrease.

At the top, he has Venezuela, Iraq, and Saudi Arabia. These three countries bounce around a lot.

Matt sometime uses a graph such as this to look at the results, excluding the very volatile countries at the top. He might say, if we exclude Iraq and Saudi Arabia (top two layers), world production has been approximately flat since 2005.

Thanks Gail, I do understand what Matt has done. I was just looking for an explanation why increases or decreases in production should be synchronized between countries. Maybe the problem is the original data or source (EIA?). The most obvious one is the one in late 2004/early 2005. A second one might be the big rise in early 2008 which works it way up the graph. Surely you can see what I'm refering to.

If you were to scramble the order of the countries on the graph, would the anomalies still be there?

I think the way the graph is put together makes it look like countries move together more than they do.

There are some things that do make countires move together. Oil demand is highest in the winter, when it iis used for heating. Oil producers arrange their schedules so as to schedule maintenace during the time of year when oill is needed least (spring and fall, I believe). This can provide some cyclicity fo the bumps.

There are also the effects of some wars and of hurricanes that affect more than one country.

A lot of times it does look like a glitch in a single curve that gets reinforced by other curves which then tends to compound the effect. I always figured that global perturbations and shocks cause these effects.

Look at the Venezuela effect in 2002-2003 !!! What the heck happened there? And bizarre how the USA and SA acted as compensating factors on either side of the glitch.

Single bounces randomly occuring for a country and propagating upward I can understand. What I can't understand is the propagation being amplified going upward. That implies a rather weird connection between the originating country and those above it. My suspicion lies elsewhere.

Wouldn't you in fact expect to see the smoothest curve on top? If you are adding random perturbations, I would think so since they should cancel each other out.

Absolutely. That is the law of statistics for independent sources of noise. The standard deviation of the fluctuations gets reduces essentially by the sqrt(N), where N is the number of independent sources.

OTOH, for dependent fluctuations, these can get reinforced, for example by OPEC decisions or global shocks. Statistics don't play an effect in these cases.

My suspicion lies (no pun intended) with data reporting and collection causing the upward propagating anomalies. I just wish there was some way of proving it. As it is, you can't assign a movement in the top curve of the graph to any particular cause or even if it is real.

With this as a background, it is easy for me to believe that if all of the resources are there, there is a reasonable possibility that US unconventional production can be ramped up further. I think there are obstacles that may get in the way of this, however.

Obstacles to a gigantic short term ramp up in the 'production' (i.e. depletion to people who have any functioning brain cells) of a huge remaining reservoir of high quality fossil fuel is good thing isn't it? If this resource is very large, it is a far better thing that the majority of it should remain in the ground until such time as we have ditched the get richer forever, conspicuous consumption economic paradigm. The last thing we need to do is to figure out an efficient way to power our SUVs and sports cars with this stuff. This resource could help us to make the transition to a sustainable system of economic production, but first we have to recover from the insane belief that consuming wealth is the same thing as producing it.

Here, here.

But IMO its likely we will see a major oil spike/demand destruction/transitioning event before we can ramp up the use of this stuff. We'll have a choice of converting cars to run on GTL/Compressed gas or perhaps burning the stuff, making electricity and driving around in PHEVs... No-one is going to want to end up the Energy Equivalent of Betamax Man, so some interesting choices ahead.


I like the low maintenance and simplicity of pure EV's, but then again I could put up with just hiring an ICC if I wanted to go a long distance.
These guys reckon they have cracked doing a recharge in 10 minutes through a normal socket - how the heck they get that much power through I don't know:
Can anyone do the maths to check what they are putting through?

Amps and volts and so on are beyond me!

They don't say "recharge in 10 minutes", they say, emphasis mine,

The new battery technology will allow full charges from any outlet in as little as 10 minutes,” said Small. “The cost of the electricity will work out to about $4 per 150 miles.

$4 implies 40 kWh delivered by the outlet, somewhat less taken on board. 10 minutes "from any outlet" implies 0.25 kWh delivered by the outlet. So recharging time could be as little as 10 minutes if the car's cells are already nearly full, or as much as 1600 minutes if they are deeply discharged.

--- G.R.L. Cowan, H2 energy fan 'til ~1996

Nope, they are definitely claiming full recharge in 10 minutes:

Luxury Electric has an exclusive license for two rapid battery re-charge patents from the Georgia Tech Research Corporation and will demonstrate that technology in Atlanta during the coast-to-coast drive.

“The new battery technology will allow full charges from any outlet in as little as 10 minutes,”


The prototype vehicle (known simply as “The Electric”) will carry some 24 Lithium-ion cells, which give it a range of around 140 miles. Each time the batteries run out, the car needs to be plugged in to a regular power outlet for about 10 minutes - so the average ‘fuel stop’ time will be longer and more frequent than it would for a petrol powered car, but still not a major hindrance or hassle.

Goodness knows how that is possible though - using your figure of 40kwh, which also sounds about right for 140miles from an EV - that works out to 4kwh a minute as an energy flow - I thought that was way over the specs for a normal socket.

They are probably charging the cells in parallel rather than in series like you would normally expect. Not only that, but they might be doing it serially, one at a time. But I don't see how that would help since you can only depend on drawing 110x15 watts unless the machine is a real electron sipper. Then again, you've got 1.65 watts you can throw into a cell at a time. A123 claims to be able to recharge their li cells in extremely short times.

I believe that there are batteries, maybe charging in parallel as you suggest, that can handle this sort of charge rate - the only way I can see them supplying it though is if they are also suing 24 regular power points!
Which is stretching the definition of a 'normal' power point more than somewhat, and you would have to carry some sort of gizmo to get the power into the car.

Sorry, I meant 1.65kw. If you suppose the pack is composed of something like 6000 cells like the Tesla, if done serially, you could devote 1/10 second per cell at that rate. It sounds rather far fetched to me, conjuring up images of Frankenstein and his monster.

A "100 mile" Altair Nanotechnology Battery (Nanosafe tm) pack **can** be recharged in 10 minutes. It was verified by Aerovironment, the late Paul McCready's company. The pack was removed from a Phoenix Motorcar SUT and hooked up to a charging station. I figured they must have had a 480 volt system pumping 450 amps into the cells. One of the techs who performed the recharge was on the Electric Vehicle Discussion List (EVDL) and his comment was "...and the cables got warm." meaning the batteries didn't.

A sedan uses about 0.25 to around 0.35 kilowatt-hours per mile. This should help in any calculations you do.

With regards to the A123 System batteries. There is an electric drag bike at It can go from 0 to 168 MPH in the 1/4 mile using 1200 - 26650 (26mm dia x 65 mm long) A123 cells. A 26650 is slightly longer and thinner than a "D" cell. The owner said that the earlier version of the bike used 990 cells which had a pack voltage of 375 volts and used about 1600 amps of power.

EEStor says that they have a "projected design" pack in the works for ZENN that holds 52kwhr of charge, weighs 300 pounds and can be recharged in 5 seconds. That's about a 200 mile range for a small sedan. 600 pounds would provide a range of 400 miles on one charge. About a day's worth of driving.

A Stanford University professor has a lithium silicon nanowire battery that holds 2 to 3 times as much electricity as a laptop battery and he thinks he can increase the capacity to 8 to 10 times as much electricity and be in production in 5 years. For the Tesla with a range of 240 miles, that could be from coast to coast on one charge.

It appears that there are batteries out there that can be recharged as fast as it takes to fill up a car tank with gasoline or diesel and maybe even faster.

The battery electric vehicles (EV) are coming. By 2020, I think more than half the vehicles on the road will be using batteries as some the primary means of propulsion in their daily driving and using gasoline only on long trips. The Chevy Volt is due out in 2010.

I think we need to use Natural Gas to make the glass plates for solar collectors (heat and hot water) for all our homes. Houses will be around a lot longer than we will be. The electricity saved by not heating with a house and hot water with electricity can be put into an EV without increasing utility generation capacity.

Putting NG into a car's tank makes me shutter at the waste and stupidity. Making glass for solar collectors would be a far better use with a very long benefit.

Yeah, there are batteries out there which can handle the fast charge - what I can't understand is how they meet their claims to recharge it in 10 minutes with a standard socket.

On another note, I am chiefly interested in EV cars as it develops the technology for batteries, which can then be used in delivery vehicles, taxis and electric bikes, trikes and scooters.

For economic reasons rather than technical it seems to me very unlikely that there will be a smooth transition to EV cars from ICC, as credit is likely to be tight or unobtainable for years.

there could be exceptions such as France, which has both good possibilities to fare relatively well as it sells its nuclear plants etc, and a nuclear power supply to power them with no issues at all.

I would see most people as entering schemes to hire a car for a day as needed, or using systems like that in La Rochelle where you go and pick up an electric run-around to do your heavy shopping and so on, rather than anything much like present car ownership systems.

For most European cities, the taxibus system should work superbly:
Taxibus | Intelligent Grouping Transportation

For everyday use I would see a whole variety of very light electric bikes, tiny golf-cart type motors and trikes, which might have a degree of weather protection.

In America and Australia, some combination of building light rail, abandoning the furthest-flung suburbs, infilling what remain and making them more pedestrian and cycle friendly together with re-zoning so that local shops and offices can supply most needs seems most probable to me.

The true EV car for personal use seems to me unlikely to come into mass use before around 2020, as we have made such a train wreck of the economy.

Yeah, there are batteries out there which can handle the fast charge - what I can't understand is how they meet their claims to recharge it in 10 minutes with a standard socket.

The name Rosie Ruiz comes to mind.

--- G.R.L. Cowan, H2 energy fan 'til ~1996

In Australia regular 10A(220V) outlets can only draw about 2.2kW. In the US and Canada I think outlets are 20A but at 110V so its the same.
There is no way that the electric car on you link would be able to re-charge the 16-24 kWh in ten minutes. More like 10hours. Even a plug in Prius would take 1-2hrs to fully re-charge.
This is why a PHEV is (going to be) the disruptive technology that dramatically reduces gasoline consumption, rather than BEV, unless battery technology improves a lot more. The PHEV gives the insurance of not running out of power, even if it is very rarely used, and allows a much smaller battery range to be workable. A bit like carrying a spare wheel.
As far as CNG goes I see it as a transitional fuel, it will be more expensive than electricity, less range than gasoline, and a real problem if you run out of CNG. Its big advantage is that existing ICE vehicles can be retrofitted.

The power draw figures you give are about the same as I had understood, so I haven't got a clue what they are talking about.

I believe that several different battery technologies have relatively fast charge, but have to use special power points.

It looks to me as though the PHEV is going to be the popular option in the US and Australia, I would fancy the EV to be the one to catch on in Europe, as most of us can get along perfectly fine within the likely range with the occasional hire car and they are a lot simpler than hybrids.

Mind you, that expectation is conditioned quite a lot by my feeling that finding finance for any car will be pretty difficult, and the very smallest EV buggies or scooters will be all most of us can aspire to - you might have to lump it in Aus and the States too, as all our economies have been run so brilliantly.

If there has been a technological breakthrough (I'm not holding my breath), it is great news. But it strikes me as indicative of the short term mentality that we as a culture have that we would look at this as an opportunity to use more natural gas for transportation or electrical generation. Natural gas is the ideal heating fuel and when it goes into decline, the alternatives are really bleak. Blue Coal anyone? LNG? The notion that we might be able to be self sufficient in terms of heating fuel for several generations strikes me as very appealing. And there is no better place to store the bounty than right were it is. So, if all this unconventional gas is now going to be added to the 'useful' column, that is very good news indeed. But isn't it time that we looked at this sort of good news as something that potentially benefits future generations instead of what is probably the most selfish generation that has ever walked the earth?

And there is always the lingering long term problem that the conventional wisdom point of view is that an increased rate of consumption of a finite fossil fuel resource base is a "solution" to our energy problems. Worldwide, we consume, from fossil fuel + nuclear sources, the energy equivalent of a billion barrels of oil every five days.

Another Excellent article Gail! Thanks for digging into the Navigant report.

Here is a quote from an EIA article on the report:

A new study from Navigant Consulting and the American Clean Skies Foundation (ACSF) suggests that the United States has ample supplies of natural gas in "unconventional" sources such as shale formations, coal beds, and so-called tight sands, which are geologic formations with low permeability to natural gas. The report finds the most potential in shale formations, estimating that the seven largest U.S. formations will yield at least 27 billion cubic feet (Bcf) of natural gas per day, equal to about 43% of the current natural gas consumption in the United States. That diverges from projections of DOE's Energy Information Administration (EIA), which predicts 26 Bcf per day of natural gas from all unconventional sources by 2030, even though tight sands are currently producing 5.8 Bcf per day and coalbed methane is producing 4.1 Bcf per day.

What is interesting is they cite a maximum by 2030 of 27 bcf/day or 9.8 Tcf/year.

The 2020 level you are showing is much higher. Did you see how the EIA came up with the 27 bcf/day number for shale alone?

What Navigant Consulting shows is an additional 27 billion cubic feet / day of shale gas at some unspecified data in the "next decade". I guessed 2020. They also forecast that tight gas will continue to ramp up similarly to what it has in the past.

I had to take these pieces, and add them to estimates for conventional gas and for coal bed methane, to get what I show in Figure 1.

At no point does Navigant Consulting mention a number for 2030, or at any other particular date. The press release is just trying to compare numbers EIA that really don't match up too well.

Ok, that makes sense. Thanks.

fig 6 forecasts about 1 bcf/d for the bakken. and i am assuming they are talking about solution gas produced with the oil.
that implies an oil rate of over 1 million bpd at the current average producing gor.

that figure (1 million bpd) is beyond "optimistic", more than 10x current rate. and of course the bakken suffers the same delima as the shale gas wells, operators have to drill ever more wells to compensate for the steep decline in existing wells.

the producing gor will probably increase with declining pressure, but so will the oil rate.

I don't think they are thinking solution gas for the oil; I think that they are somehow thinking shale gas, perhaps from a different layer than the oil. At the bottom of the exhibit, NCI gives its sources for its beliefs, in very general terms.

thanks for the reply.

but really, nci calculations ? imo, they pulled this from where the sun don't shine.

and regarding fig 6. they are showing a 5 fold increase in the next 5 yrs. i question if we can build that many state of the art drilling rigs even if it were economical.

You understand why I listed all of the "obstacles to growth" at the end, and put the "next decade" number at 2020. When one just looks at one piece of the puzzle--what gas companies say they would like to do--you can get some unrealistic views.

Very thorough post, Gail. Oddly, however, you left out one extremely important point on this issue, namely that Matt Simmons, Julian Darley and virtually every other member of the peak oil community has been warning that US NG production was going to "go over a cliff" any day now for the last 4-5 years. See, for example:

Matt Simmons1, Matt Simmons2, Dale Allen Pfeiffer, mobjectivist, Julian Darley, Culture Change,, LATOC, Post Carbon Institute, Energy Bulletin, The Oil Drum etc. etc.

Perhaps, as a relative newcomer, you may not have been aware of the long history of this issue, although I doubt it. :-)
Anyway, the spectacular failure of these peak oiler predictions is an important point which TOD readers should be aware of.
Best hopes for more honest disclosure in the future.

I am very well aware of those forecasts. In fact, at one point I planned to include Jean LaHerrere's forecast, which is the basis for some of the other forecast.

What Jean does is forecast conventional natural gas production, and assume that unconventional will have little impact. That may in fact be true, because of the various impediments that I listed, but I think it is fairer to look at the whole picture.

Writing about peak oil, I have learned to always be skeptical about anything I read, regardless of who says it.

Conventional production has clearly fallen since the 1970's. In the last decade the fall has been quite steep.

I think what Gail, myself and others are trying to judge is if unconventional can possibly scale enough to offset conventional. That seems to be happening today, but will it last and how long? These are important questions and worth discussion.

JD, do you have a method of predicting the supply of natural gas with accuracy 30 years into the future? Post your model. Let's see your improved methodology.

JD won't bite, but I think I can give it a decent shot. First of all I would model the conventional NG discovery curve, undo any back-dated growth and then apply a good reserve growth model, ala what Khebab has done recently. Finally apply the rest of the stages of the (Oil) Shock Model. This will extrapolate into the future given a variation of the current extraction rate.

And then I would repeat this for unconventional sources.

You basically don't understand the characteristics of rate-limited systems. NG reservoirs differ from oil reservoirs in the profile of extraction. To put it in terms of a simple analogy, extracting from a NG reservoir is more like sucking a milkshake from a straw. It comes out uniformly until it is abruptly gone. Oil on the other hand exhibits more of a diffusional and drift process, so that extraction tails extend for a longer period. Therefore, not as much of a cliff.

A lot of what we try to do here is educate people. Why should we hide the fact that these types of fossil fuels differ in terms of depletion? NG does show a more cliff-like behavior. If someone can state a case contrary to this, I would like to hear it.

What mitigates the cliff-like behavior for NG is the fact that we still have the Hubbert-like profile for discovery. The tails will extend just because of the curve of discoveries. "Cliff"-like behavior of NG depletion is definitely seen for smaller regions around the world where the discoveries don't have much of a statistical spread.


"....the characteristics of rate-limited systems."

i guess i agree with that to an extent, but isnt that just saying that the economic limit of a ng reservoir is higher (in energy terms). i am assuming you are refering to mainly offshore ng fields.

i believe ng reservoirs are subject to the same diffusional, if not drift, process as oil reservoirs.

and i offer as an example, the hugoton gas field of co,ks,ok and tx. hugoton has been in production for at least 70 yrs.
not likely that we will find another hugoton, however.

elwoodelmore ,
USA NG also shows similar reserve growth patterns as oil. If you look at individual NG reserve growth curves from USGS, they have order of magnitude growth over that same span of 70 years. That also explains some of the longevity, as producers only proportionally extract based on what they know they have. (A good economic rule of thumb)

The other really strange thing about NG is that fields have been burning off for eons of time (look from outer space and you can see uncontrolled NG burn-off flames all over the earth). That does suggest that diffusion does play a huge role in this, otherwise you would expect that these things would outgas much more quickly.

So I think the realistic situation is that there is a continuum of behavior, ranging from the classic caverns of NG to the more unconventional locked-in deposits that would supply stripper-well like rates. The cavernous deposits are the ones that would generate the most cliff-like behavior. And I think that is what gives us the conventional wisdom for Natural Gas.

Update Edit:
Take a look at this analysis I did earlier this year for NG. It partially models the reserve growth components.

The other really strange thing about NG is that fields have been burning off for eons of time (look from outer space and you can see uncontrolled NG burn-off flames all over the earth). That does suggest that diffusion does play a huge role in this, otherwise you would expect that these things would outgas much more quickly.

My understanding is that the this flaring of NG is to get rid of what outgases from the high pressure crude as it is brought to standard pressure at the surface. The NG is dissolved in the crude, not just slipping through it. Great stuff in "Twilight in the Desert" re this topic.


great post and discussion...!

With the flaring issue you are mentioning another "unconventional source" of natural gas, which has probably a much higher potential and lower risk than all other gas ventures:
Last year the US National Oceanic and Atmospheric Administration (NOAA) estimated that 168 billion cubic metres (bcm) of gas were flared in 2006 – equivalent to 27% of the US natural gas consumption or 30% of the EU gas consumption. NOAA said the flared gas could have fetched $69 billion if sold.
Flaring world champion is Russia, by far exceeding even the flares of Nigeria, Iran and Iraq. So far producers have simply burned the gas found alongside oil they considered too difficult and costly to recover and sell it.
From a free market economical view, with higher gas prices, more concern about greenhouse gases and a developing LNG facilities it might be worthwile to build pipelines or LNG ports in order to harness the gas. I read that even Nigeria is planning a pipeline to Europe, although I doubt that this is realistic.
If Russia will follow the free market economical approach remains to bee seen. Given their almost monopoly status for Eurasia they also might prefer to follow Hotelling's rule in order to keep prices and revenues high while minimizing investment efforts.

What is your point ??

jd, shouldnt you be feeding at the conucopian trough, this is the doomer trough.

Excellent post and comments the only thing I think thats missing from the production side is the number of rigs available to drill for NG.

The rig count this year for NG is about the same as last year but up by 5%.
We would need to probably see more like 10% increases just to stay level for UCNG production.

Given the short lifetimes of shale plays I think that rig count is the limiting factor.

It seemed to me that it was probably the availability of the particular kinds of rig gas companies wanted was really critical. If eveyone want horizontal rigs and they are all gone, it won't matter that there are plenty vertical drilling rigs left.

Probably but this should be looked into more deeply. Actually getting the trained crews esp for these long horizontal wells is probably even more limiting than getting the rigs themselves.

And I think the pipeline issues although brought up are a lot larger longer term issue than we realize.

Now I have no idea if its possible to produce the shale plays faster than they are already producing but assuming that it could be done they are really the only source of NG to make up for shortfalls in the GOM.
Given the rapid decline of these wells if they can be drained faster we could hit serious declines fairly quickly.

I think the two key issues to address are rig availability and well depletion rates. Since 2004 I have seen several references that suggest that the production rate of new wells drops by 50% to 60% in the first year. Assuming 50%/yr, the useful life of a well is about 5 years. I have only been able to find average production/well history for Texas, and we see 1967 at 350 x10e6 cu. ft./yr, 1977 at 241, 1987 at 129, 1997 at 103, and 2003,04,05,06,07 at respectively 83, 81, 75, 73, and slightly <73. (I am not using decimal places as I doubt there is enough accuracy in the numbers). I would guess that total USA would show lower current numbers, but not much different for 1967. So, for every well in 1967 we need at least 5 wells today for the same total production. Recent gas production in Texas was up 5.7% y-o-y, while producing wells were up 6.1%. Barnett shales are getting most of the drilling.
In the following I am using mid year to mid year so 6/02 to 6/03 is the year called 03, etc.
In 7/01 there were 1010 NG rigs operating in the USA, down to 620 by 2/02, and back up to 710 by 6/02. The rigs/month jiggles around quite a bit, but to a close approximation there wer the following rig counts at mid year, 2003 - 910, 2004 - 1000, 2005 - 1200, 2006 - 1390, 2007 - 1490 and 2008 1570. So we have added 660 rigs in 5 years, 100 of which were already available at 6/03, so approximately 500 rigs in 5 years. In more detail we see for mid 02, 03, 04, 05, 06, 07, 08, Vertical rigs 653, 837, 890, 1040, 1154, 1173, 1115 and
Horizontal rigs 57, 73, 110, 160, 236, 313, 455, so we have gone from 7% horizontal in 2002 to about 30% horizontal in 2008, but now the increment is => 100% horizontal.
However note the big jump in horizontal rigs in 2008, accompanied by a decline in vertical rigs. It seems likely that the only way to get more than about 70 per year increase in horizontal rigs is to cannibalize crews from vertical rigs. Perhaps the industry can recruit and train no more than 70 to 100 crews per year, even with NG at high prices, so this might be the limiting factor.
We are still drilling a lot of vertical wells, but the shift to horizontal is accelerating rapidly.
I haven't found data on how many wells/yr/rig are achieved for vertical and horizontal respectively, so I have made some guesses. If we assume that about 2%/yr of old vertical wells go out of production, and new horizontal wells have a productive lifetime of 5-6 years, and vertical rigs can drill 14-15 wells per year, and horizontal rigs can drill 9-10 wells per year, we can approximate the recent total producing wells history. At mid 2008 then out of about 480,000 producing wells, only 20,000 are horizontal. Doesn't seem like enough to drive a 7% y-o-y increase in production, after accounting for the Independance Hub contribution. Hmmm.
We do see a net increase in producing wells for 2008 of about 4%, and using the recent Texas decline rate in average well production per year of 1.5%, we should have expected an increased production of about 2.5%. The 7% seems a bit dodgy.
Maybe someone that's a lot better at modelling than I am (my capability is zero) can massage the numbers and come up with something better.
I think this approach can also be used to project a rig/yr increase rate needed to support the projected growth. Personally I think that 2008 is anomalous and there may be no growth at least for the next couple of years. For sure, with present lower price for NG there is no incentive to ramp up rigs/crews. Murray

Come to think of it we very nearly overflowed available storage in 2006 and 2007, so maybe some wells were shut in and brought back on stream in 2008??

2006-2007 seems to be the sweet spot esp for the Barnette play. You had a lot of drilling in 2003-2005 that still had active producing wells 2006 esp overlapped a lot of existing production. 2007 sees growth more because of growth of rigs etc.

But by late 2007-2008 we are now dealing with a significant number of declining wells so you have to start assigning more and more rigs as replacement rigs i.e they will be 100% used to replace existing production thats in decline.

You can look at the drilling in the shales to see this. It could have been worse but we also went with even longer horizontals with multiple fractures I believe this started in 2006 though I don't have good data so this has certainly helped not only hide the fact we where probably already overcommited by 2007 but may be why we continued to increase or held steady in 2008 or at least the first half of 2008. The decline rate is steep enough that the total can peak and go into decline in as short one year.

I'd suspect that if we cannot overcome the steep declines that we hit critical mass this year even with the new er well technology.

Also if you read about the Barnett shale a bit you get the impression that the best areas are fairly well exploited so a lot of rigs may move to the newer plays opening up the bear eating only the belly fat of the salmon syndrome. I can dig up links on this but its late.

So in anycase this is the type of dynamic that goes on top of the actual rig count. The key point is you have to discount more and more rigs as they are relegated to replacing existing production.

Worse of course is that it looks like that a lot of people would rather have the best rigs since drilling the long horizontal wells is the most profitable so you get a sense that people may start waiting for the right rig and not drill a cheaper horizontal.


I too have questioned the EIA production figures. They are not consistent with the Texas Railroad Commission figures nor are they consistent with the production figures that the producing companies report in their quarterly and yearly financials.

The 10 largest natural gas producers in the United States reported a YOY increase of 5.5% in natural gas production for the first six months of this year compared to the same period last year. However, much of that was due to acquisitions of existing wells, not drilling.

Williams Companies, in a presentation that accompanied its Q1-2008 financial report, had some data that shows that 17% of the growth in natural gas reserves in 2007 (for the ten largest companies) was due to acquisitions of pre-existing wells, not drilling.

If we subtract the production increase due to the acuisiton of pre-existing wells, then the production increase due to the drilling of new wells was only 4.5%.

I am willing to acknowledge that natural gas production increased the first six months this year over the same period last year. But these 8% and 9% figures one has to take with a rather large grain of salt.

Also at least the storage report form was recently modified.

Generally with this administration at least any changes in reporting tend to result in a better result.
The unemployment numbers etc.

Although they talk about reducing the differences between monthly data and weekly data they don't discuss if any systematic error may have been introduced.

Also, I don't know that your speculation that a shortage of manpower is the reason for the decrease in the number of rigs deployed in the drilling of vertical wells is correct. I think the decrease may be because there is a lack of demand. This is a repeat of an earlier commentary of mine, but it is germane here and may help to explain what is going on:

The subject of the cost to hire a drilling rig also arose last week.

I undertook a cursory review of last year’s annual reports of the six largest U.S. drilling contractors in the country--Patterson-UTI Energy, Inc., GreyWolf, Inc., Helmerich & Payne, Inc., Nabors Industries, Ltd., Pioneer Drilling Co. and Unit Corp., who together own about two-thirds of the nations rig fleet.

The cost to hire a drilling rig is an important part, perhaps up to 20%, of the total cost to drill and complete an oil or gas well. There has also been considerable discussion in the media about how the shortage of rigs is hampering exploration and development efforts.

What I found surprised me, because it flies in the face of popular media histrionics.

Evidently the industry has overbuilt:

With approximately 300 non-working rigs currently available in the market there continues to be pressure on daywork dayrates as well as the amount we are able to charge our customers for moving our rigs. As of February 18, 2008, our leading edge rates range from $14,000 to $20,000 per rig day, without fuel or top drives, compared to a range of $15,000 to $22,000 for the same time a year ago.

Source: Grey Wolf 2007 Annual Report

But the industry is hopeful that the glut of rigs will soon work itself out:

On the supply side, we expect a significant decline in the number of new rigs entering the market this year with an expected 50 new entrants, down from 280 in 2007. This should put the supply of rigs in closer balance with demand by year end.

Source: Grey Wolf 2007 Annual Report

I found this table from Patterson's 2007 Annual Report quite interesting. Patterson is the nation's second largest drilling contractor with a fleet of about 350 rigs:

Operational Highlights
(dollars in thousands – unaudited)

                   2003       2004        2005       2006        2007
Oper days         68,798     77,355     100,591     108,192     89,095
Avg rev/day       $ 9.30     $10.47      $14.77     $20.05      $19.50
Avg Oper Cost/day $ 6.91     $ 7.20      $ 7.72     $ 9.46      $10.76
Avg margin*/day   $ 2.39     $ 3.27      $ 7.05     $10.79      $ 8.74
Avg rigs oper.     188        211          276       296          244

*Average margin per day represents average revenue per day minus
average direct operating costs per day and excludes provisions for 
bad debts, other charges,depreciation, depletion, amortization and 
impairment and selling, general and administrative expenses.

Direct Operating Costs are marching inexorably upwards, but Patterson has not been able to pass these on to the well operators due to market conditions.

Evidently the market has bifurcated; the newer, state-of-the-art rigs enjoying greater demand and higer rates:

...we [Helmerich & Payne] are not managing the dilemma of carrying a large percentage of old, less capable rigs, while the customer increasingly votes in favor of high efficiency rig offerings.

Too many old legacy assets, often no longer suitable for reinvestment, force our peers into a tradeoff between market share and price discipline. That sounds like the classic prisoner’s dilemma with the logical best choice being price discipline. Since, after all, the market drives demand, contractors have to fight against being reduced in a soft environment and engaging in the downward spiral of rig-on-rig price destruction. This is happening now in the U.S. land drilling market.

Some industry observers have asked why drilling contractors are not exerting more pricing discipline in a market with historically high rig counts. One reason is that truly differentiated performance has driven a segmented marketplace. What we see from our end is existing FlexRigs that were working on the spot market in the last quarter of 2007 still commanding over $25,000 in rig revenue per day on average at 100 percent utilization, while competing rigs were aggressively cutting prices and in the end were still pushed to the sidelines.

Take a look at this last year in terms of margins and activity by comparing the fourth quarter of fiscal 2007 to that of fiscal 2006:
• Our average rig margin per day in the U.S. land market has only
declined by eight percent to $12,221. This daily margin is now 40 percent greater than that of our four largest peers.
• Moreover, our quarterly average number of active rigs increased by
38 percent year-over-year, while that of our four largest peers combined experienced a net reduction of 14 percent.

We have passed the point where competitors can credibly position idle, old equipment as future operating leverage. Back to the prisoner’s dilemma, the next logical exercise in discipline is to permanently remove from the market old industry rigs that are increasingly obsolete, ill-suited, and potentially unsafe in a drilling environment that is becoming more technically demanding.

--Hans Helmerich, Helmerich & Payne 2007 Annual Report

"Also, I don't know that your speculation that a shortage of manpower is the reason for the decrease in the number of rigs deployed in the drilling of vertical wells is correct. I think the decrease may be because there is a lack of demand. This is a repeat of an earlier commentary of mine, but it is germane here and may help to explain what is going on:"

Your following data would suggest that there has been a surplus of rigs, or more likely an inventory of relatively unusable rigs since 2002, and that almost all of the increase in rig count from 2003 to now has been new rigs, an average of about 150/yr. Perhaps there is a rolling retirement of the oldest rigs, a rolling inventory of marginal less old rigs currently unused, and an annual introduction of closer to 200 new rigs. Interesting.

Re Memmel's point - rig count has been growing by about 100 rigs per year, and horizontal rigs from very few to near 500 now. Yes, the oldest horizontal wells are now dropping out of production, but there weren't very many of them, so their brake on production growth is still pretty limited. Producing horizontal wells jumped by about 100% 2004 to 2005 from a low number, 50% 2005 to 2006 from a higher number. Unless the number of new horizontal rigs per year accelerates considerably, we will get to the point where the annual increase is only near 20%, and the early decline impact of the older wells is a high percentage of current production. This won't really kick in until the 2010 wells are hitting their early declines, and later than that if new rig introduction accelerates. It is this kind of observation that needs to me modelled. I am playing with a manual spread sheet which is very limiting, but the best I can do.


I don't know if you saw it or not, but an engineer that works in the Bakken shale did this study a few months back for TOD. It illustrates some of the dynamics that occur with these reservoirs that deplete so rapidly and may help you in your modeling:

Hi Gail,

Using the EIA's data for planed power plants

I come up with about a 6.3% increase between 2008 and 2015, with most occurring before 2011.

Year Fuel Total  Summer MW  Winter MW
2008 NG 93 8,823 9,851
2009 NG 57 7,322 8,132
2010 NG 21 4,179 4,583
2011 NG 7 2,532 2,798
2012 NG 3 1,322 1,450
2013 NG 2 237 273
2015 NG 1 154 177
184 24,567 27,264

The average by 2015 will be about 26,000 MW which at 85% up time gives 193,596,000 MWhrs or around 1.3 TCF NG at 50% plant efficiency.

If in addition, we switch all 134 million passenger cars to CNG plug-in hybrids (T Boon’s idea but done with high-efficiency vehicles), you add another 10% consumption (takes 20 - 25 years at a 5.8 million cars/year @ current scraping rate to convert the fleet), so if the supply is there and below oil/coal prices, then I think that industry will think up ways to consume it.

I see natural gas as one of the lifeboats that everyone will pile into as oil becomes too expensive and/or supply declines. As a result, the issue may become not that we can’t use the increased supply, but will there be enough. – SMH

I agree. I originally wanted to talk about what the new NG might be used for in the same article, but decided I needed to postpone that part of the discussion.

I think it will be a grab as to who gets to it first. It won't necessarily be the best allocation of the resource. I think the chosen approach is likely to sidestep the need for new delivery pipelines, because these are too slow and expensive to install. Instead, the uses that are likely to win will be close to where the gas is produced, or will mostly fit into existing pipelines.

Hope I'am not posting this on the wrong thread, or it has has not already been posted, But Matthew Simmons' is in the news again.

Aluminum index, topped in mid may
Steel index, topped in mid may
Coal index, topped in late june
Oil & Gas index, topped in mid may
AMEX Oil index, topped in mid may
Oilfield & Equipment index, topped in early july
US Gas Distribution index, topped in early july
AMEX Natural Gas index, topped in early july
AMEX Financial Index (scary!), short term top in early june
NYSE Financial Index, short term top in early may
Dow Jones World stock index, topped in mid may

As you can see if you look at the charts, aluminum and steel topped out first. (It was actually Mechel that first brought me to the realization that this commodities roller coaster might be going over the edge.) Given the information on this thread, I am surprised that natural gas did not lead by falling first. This overshoot should have been known and acted upon by insiders many months ago, causing natural gas futures to break down at least in mid may if not sooner. So why did natural gas keep running up all the way into july?

At any rate, I think this thread does help to explain why gas has fallen harder and faster than oil.

What's really frightening about those charts is that if you open the AMEX Financial chart and the Dow Jones World stock chart each in a separate window, and then toggle between the two really fast, you can see that they match each other almost perfectly. That is not good...

Iconoclast421: I wasnt going to say anything, but since you broached the subject, You have good reason for concern.
The markets are presently heading south faster than a Gypsy roofer, when it rains, for good reason. I dont need to tell this crew here about petro dollars...Well
its all tied to the same anchor. The American dollar is anemic, not just weak. The American gov is going begging, cowboy hat in hand for credit and as we all know, credit is tight right now.
The sentiment they are trying to sell everyone is....
The world will seek safe harbor and America is the safest port in the storm. Trouble is, Nobody is buying BS these days and its a hard sell. Alan is the only guy I know who has the cajones for NOLA.

World markets arent in free fall because growth is slowing....growth is slowing because American markets and its fiat currency and banking system is crashing.
Auto sales, housing crisis, unemployment, commodities
tumbling et cetera.
The BAU crowd is saying "Since America entered into the decline will come out first" hahahahah
Yeah sure! and the last shall be first and the first
shall be last sayeth Mark Hanes in his sermon at the church of the back sliding IRA's

It seems like for natural gas the comparison to prior year is not very meaningful, if you just have a month or two (say Jan 08 vs Jan 07). People may have thought the first couple of months were a fluke. Also, EIA data is very slow to report. It wasn't until April and May production reports were available (July and August), and storage started filling up, that the people started realizing what the problem was.

Hello Gail,

Great work! According to the USGS Nitrogen PDF: the US currently imports 44% of its natgas-sourced Haber-Bosch [H-B] ammonia, urea, and other nitrogen [N] products in the various other types of I-NPK. From a national food security standpoint wouldn't it make sense to go to no more imports, and instead use this NCG to make our own ammonia & urea?

Besides improving our national security, this plan could also help keep natgas prices from getting too low, thus making it financially easier for the NCG extraction timeframe to continue into the future longer. If desired, building massive stockpiles for inclusion at numerous 'Federal Reserve Banks of I-NPK' is an easy way to store 'transformed natgas'. This could help smooth the seasonal pipelined pricing fluctuations as an additional benefit.

Obviously, natgas is finite, thus we need to be moving to the entirely natural loop of full-on O-NPK recycling-->this will be a multi-decade process till we achieve a high proficiency. IMO, burning natgas for personal transit now seems like a senseless waste when our children and grandchildren will need heating warmth, kitchen stove fire, and H-B N to supplement the growing of their food stocks.

If we still need to provide another bottom price support for NCG: a lot of natgas can be burned if we massively build out Alan Drake's RR & TOD ideas everywhere plus his Strategic Rail Reserve. Imagine how much of this natgas it might take to smelter and/or recycle the steel for a postPeak rail network that could be the envy of the world.

Bob Shaw in Phx,Az Are Humans Smarter than Yeast?

One advantage of making nitrogen fertilizer from the NG is that it can be done near the NG source, so one doesn't have to build miles of distribution pipeline. If there is a way that nitrogen fertilizer can be made using wind, that would be even better. We could save the NG for other uses.

IIRC, NG would have to be at about $20/decatherm for wind (at $.07/kwh) to be cost-effective.

Interesting ideas toto. And as much as my libertarian side gags at the thought I think it would take gov't action to make such ideas into reality. The NG to fert at the source was tried by a fella named Jack Stanley back in the 70's. He bought up much of the NG production in S TX with the plan to do the conversion and ship the product around the world form the port at Corpus Christie. But just as he plowed himself deep into PERSONAL debt ($1 billion+ back when that was a lot of money) the bottom of the global urea market dropped out from underneath him. There was chat at the of a global conspiracy by the folks who controlled the market at that time to cripple his efforts. Who knows? I would think that any major efforts along the lines you describe would require some sort of sovereign guarantee. And perhaps a little muscle to back it up.

Excellent post as usual. I must agree with JD above that most in the PO community were wrong on the NG situation for North America.

Question: is it the case also for Europe?

Another important question is the potential impact on CO2 emissions if unconventional resources are heavily exploited. Some have argued that Peak Oil will solve the climate change crisis (for instance Kjell Aleklett). NG accounts currently for 20% of the US current emissions:

Global emissions by source:

I don't know if Hansen is taking into account this amount of unconventional NG:

Yep Khebab....the PO community didn't see the impact of UNG coming. But to be fair, I can assure you that most of the oil patch didn't either. Even being hip deep in an UNG play right now it difficult to believe some of the results I'm seeing. And it wasn't just the results of the technology advances but also the speed. And that was due to the real source of the new research: the service companies. Had the research effort been led by the majors, as it was 30 years ago, the UNG plays would have taken many more years to develop where it is today. As I mentioned in another thread, you, Khebab, could drill and complete a UNG horizontal well just like Chesapeake if you had the lease and the money. The service hands designing wells for C wouldn't tell you how they are doing it for C but if you requested a well design for a hole next to one of C’s guess what it would look like. These service companies are making money like never before. If you owned a lease in one of the plays you would likely get a call from one of them before you could reach out to them. They are one of the real drivers of the plays. The operators are just supplying the leases and capital.

What ever UNG potential there is in the EU it won’t be long before you’ll see the same service companies pitching themselves over there. Most of the big companies are deep into international work and already have folks on the ground over there. All they’ll need is EU operators to start writing checks.

OK, well let me now present a disturbing bit of a forecast.

If UNG ramps up nicely, where will we get our Helium supplies from? :(

The operators are just supplying the leases and capital.

Not too flattering to people like myself whose career was always as a "company man" and then later as a person who identified the leases and sold them to the guys with the capital, but you are absolutely correct.

In looking back over my life, my career and my achievements I've thought about what you say many times. In the oil and gas business it's not the operators who, for the most part, have the technology, the expertise, the equipment nor the highly trained personnel to drill and complete the wells. It's the contractors and service companies. Almost everything is contracted out, and without these contractors there would be nothing.

ROCKMAN, I always appreciate your comments and you, as an industry insider, bring a perspective to this board that is very much needed. But beyond that it seems you are able to set yourself apart from the industry and, even though an industry insider, to look at it as if looking from the outside, to pierce through some of the myths that dominate thinking within the industry.

Your comments and thoughtful observations are always appreciated.

Texas serves as a pretty good model.

In 1972, we produced about 7.5 TCF from 23,000 gas wells.

From 2002 to 2007, we increased our production from 4.8 to 5.7 TCF, but it took about 23,000 gas wells.

In other words, in order to boost our net production by 0.9 TCF over a five year period, it required the same number of wells that we had in total in 1972, when we produced 7.5 TCF.

It seems to me that in order to keep our total gas production rate increasing nationwide, we are going to have to have an infinite rate of increase in the number of wells that we drill, complete and connect to gas lines.

For Texas, the gas well count, at our current rate of increase, would like like this:

2002: 65,000 wells

2012: 118,000 wells

2022: 215,000 wells

2032: 387,000 wells

Note that the incremental rate of increase in net production per well has been about 100 MCF per day. On a BTU basis, this is about 17 BOE per day per well.

BTW, the Texas RRC has added a Barnett Shale summary section. So far, it looks like production is going to be approximately flat year over year in 2008, versus 2007.

It might be interesting to look at the total cost of new wells versus the incremental increase in net production per well nationwide.

I suppose we could do a similar calculation for world crude oil production. In May, 2005 the EIA showed it at 74.3 mbpd. In May, 2008 (subject to revision) they showed it to be 74.5 mbpd. I wonder how much money the industry spent in three years in order to increase the net crude oil production by 200,000 bpd, from May, 2005 to May 2008?

I am still convinced Barnett Shale production for 2008 is substanially missing from the Texas RRC numbers, and even some of the late 2007 Barnett Shale.

I do agree that you will need an awfully lot of wells to keep production going, though.

I think that is why the commission put up a Barnett Shale summary. The detailed, and reportedly not fully updated, lease data were showing a production decline.

I found these rig counts on Baker Hughes web page...

It gives rig counts for the entire Bend Arch-Ft. Worth Basin, but probably all these rigs with the exception of a dozen or so are working in the Barnett Shale.

Interesting to note that the rig count peaked at 200 in Nov-Dec last year and has since dropped to 183.

It's going to be a very interesting year for the Barnett Shale. If rig counts continue to fall, and if producton follows the same trend that the Bakken Shale did back in 1991, then we will see total production begin to plummet.

In the case of the Bakken Shale, there was an inflection point on the curve of the # of producing wells where the # of producing wells is still on the increase, but was just not growing as rapidly as before. And despite the fact that the number of wells continues to grow, production begins to plummet.

Perhaps that inflection point is where we currently are with the Barnett Shale.

Thanks Gail, this was just what I was looking for. But there are more open questions.
As far as I understand, tight gas or shale gas is - in contrast to conventional gas - not driven by water but only by the reservoir (gas) pressure.
Is there anything like a secondary recovery method in order to keep the gas flowing when the reservoir pressure is down? If not this type of resources appears a bit like a flash in the pan - however I've read that many shale gas wells had a small but steady production for decades.
What is the typical productivity of conventional gas wells (compared to tight or shale gas wells)?
What is the typical well spacing of conventional gas wells? For shale gas a recent article in World Oil mentions "much denser well spacings, in some cases down to 10 acres".
What is the typical productivity of conventional gas wells (compared to tight or shale gas wells)?
The same article says "Recovery factors vary between 5% and 20%, sometimes higher." How much are they in conventional gas?

How about the potential of unvonventional gas in other parts of the world?

Unconventional gas will come to other parts of the world. However, since the majors slow to the party in UNG the international profile is very low. Most people (geoscientists) at major oil companies still dont know what the impact of unconventional ng is in north america. I liken UNG to the advent of mammals during the Cenozoic. THe majors are the dinosaurs leading each other to the grave. Case in point--Chevron--no unconventional gas that I am aware of.

Could we infer that if UNG peaks in the U.S during the next decade that it will be 15-40 years before UNG peaks worldwide?

Well your running into the issue with National Oil companies they don't just need profits they need fantastic profits. I doubt you see a lot of unconventional production in regions controlled by the national oil companies. The majors are arguably better needing say just extraordinary profit margins but outside of Canada few places are willing to allow oil or gas to be extracted for what we would call regular business profits. And if the great shale experiment proves to be what I think it will which is a decent but relatively small amount of NG extracted at large and increasing costs i.e the treadmill most places will opt out until profits are at least lucrative.

Bottom line is that any significant attempts to extract unconventional gas with the exception of Canada will probably come much later and will be in response to shortages of high value products like ammonia fertilizer.

As a energy source I doubt it as feedstock for the petrochemical and esp fertilizer market much later on say twenty years from now yes. I might mention I expect the same situation to evolve in the US as NG gets more expensive the critical uses will necessarily win.

The good news is of course that we probably have enough unconventional gas world wide to ensure all our critical use cases are met the bad news is this is about all its useful for in the longer run in my opinion.

The good news is of course that we probably have enough unconventional gas world wide to ensure all our critical use cases are met the bad news is this is about all its useful for in the longer run in my opinion.

I do not think that this is bad news. Finding a huge new source cheap fossil fuel would be a disaster, since we would just use it to keep the growth economy functioning for a while longer. We need to come to terms with the fact that we live in a finite world, and the evidence is abundant that we are not going to do so by means of rational, objective reflection on the future consequences of our actions. Cold, hard necessity alone can bring about a new view of economic reality. The current popularity of anti-global warming actions (which, in reality are completely ineffective) is driven primarily by a desire that climate change should not interfere with economic 'progress' rather than by a realistic understanding of the nature of our predicament. Admittedly your situation is extremely grim when you have view rising energy costs as a good thing, but when the prevailing economic orthodoxy equates the consumption of wealth with the creation of wealth you are left without any other options.

Well despite what people think about my opinion if we had not burned up our NG resources like we have we could have reasonably transitioned off of oil to CNG. In a lot of ways CNG is a better fuel then oil based fuels and it certainly lends itself to using solid oxide fuel cells or even reformers etc. This matches well with electric drive and once you have electric drive for anything then the power source is flexible.

But for what ever reason and I'm still trying to grok it it seems that when you exploit resources you tend to maximize all of them via partial substitution i.e fuel oil vs NG etc etc. The maximum power principle seems to be esp damaging when you can partially replace one energy source with another.

The problem is that the good side which is arguably moving to lower overall C02 emissions is not matched by a path thats acceptable to the current energy users. For example I love how people show how the US has had all this growth without using more energy and completely ignore the energy usage in China for imported goods.

The orthodoxy does not in general even recognize what it is. The reason this is important is that a decline in oil usage and the overall economy make make things a lot worse in the beginning on the global warming front counter acting our C02 emissions we have a global dimming effect from the coal fired plant in China and we have significant C02 absorption from algae blooms from global fertilizer run off. These are not good things but the point is we have heavily modified the climate and its equilibrium in a number of ways to the point that reaching a good endpoint i.e lower C02 emissions via a declining economy may well lead to sharp shorter term climatic changes as the other aspects of how we have impacted the earths climate change.

To bring this back on topic the way out in all these cases seems to have been cheap NG and cessation of the use of coal and oil coupled with aggressive use of renewable sources and nuclear power. But this would have had to happen before China chose to industrialize using coal. But today by not doing the right thing we probably have reached the point that as particulate emissions are cut the greenhouse gas load will lead to a rapid increase in temperatures. The warming after the Depression and well know short term volcanic climate effects point towards a pulse of warming during the years following a drop in the particulate load in the atmosphere. Clear skies with elevated C02 levels are not a good thing not to mention that without the particulates you get more water vapor without lower cloud formation and water vapor is a potent green house gas. Right now the high load of particulates and aerosols result in greater cloud formation.

So bottom line by doing nothing we have probably inadvertently made our problems much worse. A fast economic slow down in my opinion is capable of causing a major perturbation to the climate and NG was the only fuel that would have been a viable transition fuel.

I had not thought about the cooling effect of particulates. However, it is not clear to me that a slow ramp down of fossil fuel burning would mitigate the effect of the removal of particulates. Yes, you would be removing the particulates more slowly, but you would also be adding more CO2. Would the end result really be any better? I suppose you could try some kind of geo-engineering where you deliberately inject particulates into the atmosphere in an effort to counteract the CO2 green house effect. I suspect, however, that such efforts would be very expensive and the results highly unpredictable.

A substantial amount of the melt of arctic ice may be due to soot, and reducing that should help at least partially.

I respect your opinion--wheat among the chaff. what makes you think that we have squandered our Gas resources? What if we havent? I think that if UNG is economic at current gas prices we have a supply that will bridge us to sustainable fuels.

I do not know re sustainable time frames. I do know that CNG can provide most transport fuels today (if anyone would listen). I think the biggest roadblock is currently the automakers. Why arent there bulding CNG vehicles?????

Tant pis. I hoped that there were at least a few chances left for Europe. Lucky Russia!

From the graph:
* NG use rose from app 17.5 in 1990 to 21 in 2008 in 18 years. That's about 1% a year
* NG use is projected to rise from 21 in 2008 to 38 in 2020 in 12 years. That's about 5.1% per year.

The 1% rise was during a period when NG was relatively cheap. The 5.1% rise is during a time when NG will become progressively more expensive.

This does not sound very logical to me.

I think if oil is constrained, and it is even more expensive, it might happen. If CNG is used as a transportation fuel, it can quickly mop up any surplus.

It may be worthwile to have a look at a 2007 article in World Oil: The geological consultant Arthur Berman compared the Barnet shales with the "plank road fever" of the late 1840s. Back then people followed a hype to to cover roads with wooden planks - and failed due to wrong premises.
Berman: "The economic premise for plank roads was that the roads would last for about eight years before they had to be resurfaced, according to civil engineers of that time. When it became clear that the planking wore out after only three or four years, plank road fever ended as quickly as it had begun and became a part of transportation history by the mid-1850s."
Further down he wrote:
"The rush to lease and drill thousands of Barnett Shale wells before understanding if initial economic assumptions were valid is hauntingly parallel to the plank road fever phenomenon of an earlier time."
Barnett's conclusion was due to a study showing that under the gas pricing scenarios estimated in 2006 less than one-third of wells were likely to be economic under current gas pricing scenarios.
This may have changed meanwhile.

But there was another result of this study, which should still hold now and which I find much more disturging: If I understand these numbers right the production decline rate is completely different from conventional oil or gas production:
It goes down at an exponential rate.

For the examined horizontal wells the data are:

Year 1: BCF     0,575
Year 2: BCF 75% 0,144
Year 3: BCF 90% 0,014
Year 4: BCF 90% 0,001
Year 5: BCF 70% 0,0004

(A detail I don't quite understand is what the BCF% numbers mean. Does anyone know?)

This strengthens my suspicion that the present nationwide shale gas hype is nothing but a straw fire that temper down to a decent glow will within a few years. Maybe many of these projects will be profitable at current prices, but this drilling hype is no base for a sustainable energy supply.
Gail, if I understand these data right then there won't be a need to build so many more gas storage or pipeline facilities, let alone things like gas power plants.
There won't be the gas to fill them.


That table has nothing to do with acutal well performance. Instead it is a model he used that would yield a 5-year payout. He then examined the production from 600 individual, actual wells, one by one, to see which wells would meet or exceed the production set out in that model. And what he found was that of the 600 actual wells he examined, only 78 made enough gas to meet or exceed the model. In other words, only 78 wells would make enough gas in the first five years to recover the cost to drill and complete the wells (in the oil industry this is called "payout").

Let me try to use an example to explain better. Let's say we have 600 people who weigh 250 lbs. enrolled in a weight loss program. We set out a schedule of weight loss that we consider to be an acceptable goal as follows:

Original weight           250 lbs.
Weight after 1st month    225 lbs.
Weight after 2nd month    205 lbs.
Weight after 3rd month    190 lbs.
Weight after 4th month    180 lbs.
Weight after 5th month    175 lbs.

At the end of five months, however, only 78 of the original 600 enrolled in the weight loss program have actually lost this much weight. Some dropped out the first day or two. Some dropped out after the 2nd month. And some made it to the end of the program, but instead of having lost 75 lbs, maybe they've only lost 25 lbs.

The percentage figures are YOY decline figures. In other words, the second years production is 25% (100%-75% decline) of the first year's production. The third year's production is 10% (100%-90% decline) of the second year's producton.

As he points out, the fact that only one out of eight wells has achieved payout in 5 years or less is not only horrible, it is worse than horrible. He certainly can't be accused of setting the bar too high. Most industry players look for a 3-year payout, a 4-year payout at most, on development drilling with success rates of 80% or more.


of course the article is about the profitability of the projects but I was really looking at the well performance.
Your statement that "The percentage figures are YOY decline figures" confirms the concept of an exponential depletion (which sounds logical to me for a solely gas-pressure driven flow).

The following graphs illustrate this behaviour:

Barnett gas shale production performance (linear scale)

Barnett gas shale production performance (logarithmic vertical scale)

As far as I understand this production performance is considerably different from the production performances of all other fossil fuels, as it has a much steeper decline rate.
Below I sketched a graph comparing the typical production profiles. It is only a rough scheme but it should give the general idea:


  • The gas shale production declines rapidly as this gas is only driven by gas pressure.
  • Conventional gas is additionally driven by water drive, i.e. its buoyancy compared to the surrounding groundwater. Therefore there is predominantly only a slow decline - until all gas is replaced by the rising groundwater, resulting in a sudden drop of production
  • Depending on the type of deposit conventional oil can be driven by formation pressure and water drive; later the oil can be moved by artificial water flooding etc., resulting in a slow but steady decline. In this graph I neglected the effect of measures like fill-in drilling.
  • Heavy oil (Orinoco type) or oil sands don't move by natural drive and are rather mined like lignite deposits. If the open pit mining of oil sands is run like a typical lignite mine then its output should be rather constant. The output of heavy oil wells depends on the drilling and heating workflow, which also may be rather constant.

This is a very rough scheme but it should show the general idea. Of course an even better idea would be build a more precise production model supported with real empirical data (for example I have some for lignite).

This could help to model the behaviour of resource types, which - unlike conventional oil - weren't modelled before.

Below I sketched a theoretical production model of shale gas, based on Gail's posting and its comments.

Theoretical regional gas shale production performance


  • In the first year (hypothetically 2008) there is a gas shale drilling hype (like what is happening now), resulting in a big batch of new shale gas brought onstream.
  • This leads to a gas oversupply and a shortage of drilling equipment etc. - as a result in the next year (or whatever time lag) new developments are discouraged.
  • Due to the rapid oil shale production decline gas prices rise again, encouraging a second wave of development activities, which is limited by the availability of production equipment, manpower etc.
  • In the following years more shale gas is added depending on the availability of new well casings, new pipelines etc.

A factor I don't know is how far the well casing can be recovered and reused (or at least materially recycled) after a well is abandoned.
If (most of) the steel tubes are "lost" underground the availability of additional tubes may be one of the major the long term limiting factors for future hydrocarbon production, as shale gas (as well as heavy oil) needs much more drilling per gas yield than conventional gas. Thus we'd not only face an EROEI issue, but also also an issue of EOLC (Energy 0utput per Lost Casing).


Sometimes a portion of the casing can be recovered but ususally not much. The larger casing is cemented in place. Inside that casing another sting of casing is run thru which the well produces. This production tubing is often recovered but usually has little value beyond scap prices. In order to properly plug a well some of the production tubing must be removered but the expense (small rigs are used to do this) is often more than the value of the steel.

There will never be a lack of casing. Volumetricly, it a rather small amount compared to just about any other major industry. But cost is another matter. We hit our year end 2008 projected casing costs back in July. Partly because of demand but also do to production losses on the iron ore mining side.

I'm familiar with that article. You can find more than one place on TOD that I have linked to it.

What happens with tight gas and with shale gas is that those drilling for gas gradually get their technique so it works better. I expect that most of the gas companies went into Barnett Shale, knowing that the first wells would be losers.

Gradually, methods are fine tuned (horizontal instead of vertical wells; different "frac" ing techniques; more fracing.) It is with the fine tuned techniques that unconventional gas production can make sense. The wells will still face big decline rates, but on average, production will be up.

When Arthur Berman did his analysis, it was comparing some of the early wells against his model of required production for wells to be economic. It could very well be that those wells we not economic, but that recent wells are.

Over the long term, I expect the price of natural gas to go up. This will also lift which wells are economic.

Thanks for your comment. Again, I am not concerned about the economical viability but about the flow rate due to the bottlenecks you described. Anyway, we will see soon if this concern holds true or not.


An interesting aspect of the Barnett Sh has developed over the last few years. As you point out there was a steep learning curve in drilling and frac'ing this formation. Several years ago operators went back to early wells which were now flowing at fairly low rates and used more advanced frac'ing techniques. Not only did they discover the new methods worked better but that often the new fracs went into sections of the reservoir that had not been produced. I can't off a quantitative view of these successes but I hear it's become common place. The new fracs are expensive but not compared to the cost of a new well. Additionally, there is no added cost for the lease or surface equipment. I can't speculate on how many other plays might have well life extended in a similar matter: it's a rather complex phenomenon related to change the stress field in the rock. But in the BS, from just some rough numbers, it might add 20% to 40% in the ultimate recovery. And even more important for the public operators, it's a quick and fast way to prop up those steep production declines.


Would it be possible to share any assessment on the potential for low and medium enthalpy geothermal applications for the fields post recovery? From what you write I imagine these frac'ed areas must be substantial. And to what temperature ranges the water could be brought?

Not so much off-topic considering what fuel would normally be displaced by it.



If you're thinking about circulating out hot water on some sort of a loop basis there isn't much potential. The transmisability oif the fracs are much to low to flow any significant volume of water. Additionally, many of the wells are not deep enough to see very high temps. But the biggest problem is the deliberate effort to avoid the fracs in two offsetting wells from interesting each other. This would kill any chance of injecting into one well and recovering from an offset.

Twenty years ago a significant effort was made to evaluate oil patch wells for geothermal recovery in the Gulf coast. No real success at that time. Not sure if current prices could renew any similar efforts.

methinks thou dost protest too much (comment to many of the doomers here who don't want to recognize the reality and economics of UNG)

The industry experience in shale gas is lognormal wrto production and payout. In other words, 25% of the wells that are drilled pay for all. You cant look at well averages because the good wells pay for all the others. You must look at the aggregate.

At the current NG prices ($7.40), most of the shale gas plays are paying out a bit better than 10%. All in F&D costs vary from $5 to $8/mcf.