Can US Natural Gas Production Be Ramped Up?
Posted by Gail the Actuary on September 4, 2008 - 9:35am
Topic: Supply/Production
Tags: barnett shale, coal bed methane, natural gas, original, shale gas, tight gas, unconventional gas [list all tags]
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?
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.)
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:
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:
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.
Previous unconventional gas posts
Many readers will remember that I have written previously about unconventional natural 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.
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.
Gail,
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.
Gail,
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.
DS,
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:
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.
Gail,
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.
Gail:
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 treadmill....now 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.
Tom
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 quarterOf 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.
DS,
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...)
titan,
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 le