US Natural Gas: The Role of Unconventional Gas
Posted by Gail the Actuary on May 19, 2008 - 7:00pm
Topic: Supply/Production
Tags: American Petroleum Institute, natural gas, tight gas, unconventional natural gas [list all tags]
US natural gas production has been flat for a number of years. We keep hearing that US production is expected to begin declining sometime in the next few years, but it doesn't seem to happen. While it is not obvious from most published data, the reason production remains level is because unconventional gas production has been rising at the same time that conventional production has been declining. In this post, I will look at unconventional natural gas, since it plays such a pivotal role.
Introduction
One reason I am writing this post is because only a few days from now (May 20-21), I will be visiting BP's tight gas facility in Wamsutter, Wyoming on a trip sponsored by the American Petroleum Institute (API). I may have the opportunity to ask some questions. I thought that if I put together a post outlining a little about what we know about unconventional gas, and in particular tight gas, it might put me in a better position to ask reasonable questions, if I get a chance to do so. Also, readers may alert me to some issues I might not otherwise be aware of.
Unconventional Gas and Tight Gas
The major forms of unconventional gas are tight gas, coal bed methane, and shale gas. The production of all three have been rising in recent years. Tight gas is the largest of the three. Production of all three were encouraged under Article 29 of the Internal Revenue Code, Alternative Fuel Production Credit, which became effective in 1980.
One could write volumes on any of the types of unconventional gas. To keep this post from getting too long, I will focus on unconventional gas totals and on tight gas.
Production Forecasts
Figure 3 shows a natural gas production forecast that I found on a BP website. It is not too different from other forecasts that one sees for natural gas: Conventional natural gas production is expected to continue to fall. The various unconventional sources of natural gas will rise to keep production flat for several years. Demand for natural gas is expected to be greater than the amount that can be supplied using conventional and unconventional production. We will try to meet the supply shortfall with imported liquefied natural gas.
We all wonder, "How reasonable is a forecast of this type?" Can tight gas production be expected to continue to grow for several more years, or will it quickly reach a peak and decline? Should we be concerned in the next few years? Will unconventional gas actually do better than forecast? I am not sure I have an answer to these questions, but I will try to lay out some of the issues involved.
What has the EIA's track record on forecasting unconventional gas production?
EIA's track record has been one of consistent under-estimation of the amount that would be produced. This is an exhibit from one of Advance Resources International's (ARI's) papers showing EIA's forecasts and the ultimate amount produced:
EIA's has also tended to miss the decline in conventional natural gas, so that its track record in total has not been as poor as for the pieces. Going forward, the EIA's forcast (from the 2007 Annual Energy Outlook) is shown in Figure 5. It forecasts some increase in unconventional, but not as steep a rise as in the past. In Figure 5, NA means not associated with oil production; AD means associated dissolved.
Doesn't natural gas production tend to peak and decline like oil production?
The United States has different sources of natural gas - conventional gas, both on shore and off shore -- and the various unconventional sources. Geological factors do play a role, as with oil, but there are other factors that are important as well. I think of natural gas as more of a "pump what you need each year" endeavor, until the supply runs low, rather than as having the typical peak and decline pattern that we see with oil production. This is part of the reason production has been flat for many years.
One can see the impact of geological factors when one looks at Figure 1, which shows the decline in conventional natural gas (offset by the rise in unconventional). Reserves for conventional natural gas have also been declining, and almost everyone believes that conventional natural gas production will continue to decline in the future.
Price and technology also play major roles in determining the amount of natural gas that is pumped, much more than we think of with oil.
The price of natural gas depends on supply and demand. Natural gas is fairly plentiful around the world. While it is difficult to ship natural gas, there are indirect ways the foreign natural gas can compete with US natural gas. Chemical industries can move to cheaper sources of natural gas. Also, products like fertilizer can be made abroad, and shipped to the United States. In recent years, pipeline imports of natural gas from Canada have helped to hold down US natural gas prices. Price is also affected by availability of pipelines and by competition with coal and with petroleum.
Historically, the price of natural gas has been highly correlated with that of oil (R squared = .82 for 1986 to 2007, comparing the wellhead price of gas with the price of West Texas Intermediate (WTI) oil.) On Figure 6, I show the wellhead price per 1,000 cubic feet of gas and an estimate of the price of gas equal to 10.9% times the WTI oil price per barrel. Figure 6 shows annual averages for he years 1986 thorough 2007. For 2008, the amounts reflect recent May 2008 prices (WTI= 125.83; natural gas = 11.71). Recent natural gas prices seem to be lagging behind their historical relationship with oil, leaving some room for natural gas prices to rise.
What is tight gas?
Tight gas is natural gas found in reservoirs with low porosity and low permeability (generally sandstones with less than 1/10th of a millidarcy permeability). Tight gas requires multiple fracturing to in order for any significant amount of gas to be available. Drilling for tight gas has been compared to drilling a hole into a concrete driveway--the rock layers that hold the gas are very dense, so the gas doesn't flow easily.
Until recently, tight gas was considered non-economic to produce. Recent technological advances in a number of different directions have made it increasingly possible to extract tight gas. The higher recent prices of natural gas have also tended to support unconventional natural gas production. There is a huge amount of tight gas in place. Even with technological advances, the challenge is finding a way to extract it economically.
Where can tight gas be found?
This is a map from the Advanced Resources International website.
Based on Figure 7, one can see that tight gas resources are very widely distributed. When wells are drilled, there is a very high rate of successful (not necessarily economic, however) wells--approximately 98%. With such widely distributed resources, the challenge is finding "sweet spots" that can be more economically extracted, and developing techniques that will do this in a cost effective manner.
I have not shown maps of coal bed methane and shale gas, but they are also very widely distributed.
How does technology come into play?
Some examples where technology has come into play with tight gas formations include:
• Better technologies to find the "sweet spots" within formations.
• Research on the optimal spacing of horizontal wells.
• Developing fracing fluids and proppants for stimulating the wells, and determining which is right for each well.
• Developing low-energy deliquification methods to separate water from the natural gas.
• Developing ways of reducing the ecological footprint, such as drilling multiple horizontal wells from the same pad.
• Developing methods for drilling wells more quickly and at lower cost.
In presentations, a person sees graphs such as this one, showing efficiency gains. (EUR is estimated ultimate recovery):
The effect of these changes is to improve Energy Return on Energy Invested (EROEI), relative to what it otherwise would have been. With small changes, the economics can be improved enough to make a larger portions of sites economic, increasing the amount that is economically recoverable.
How has the amount of research on unconventional gas production been changing?
The amount spent on research and development has been falling. The amounts in this exhibit represent a summarization by ARI of the expenditures of 29 energy-producing companies.
There is a long lag between research and its widespread benefit--estimated to average about 16 years by the National Petroleum Council. During the 1980s and early 1990s, the Gas Research Institute (a federal program) and the Department of Energy sponsored research programs. These programs contributed to the higher level of research spending during these periods. The research programs of the 1980s and early 1990s are now bearing fruit, in the form of increased unconventional gas production.
These research programs have been discontinued. Companies are continuing to do some research on their own, but the amount is lower. There is a very real difference between (1) a government program, with funding by companies and with applications tested at many different sites, and (2) each company doing its own research. If each company does its own research, it can patent the new application, and eventually use it to improve its own results. The present value of the benefit is relatively small, since it benefits only the company itself, and the timing is quite distant. It may eventually be able to sell the benefits to others, but this will take time.
If companies can work together on research through an organization such as the Gas Research Institute, the results can be shared widely, more quickly. These shared results benefit all, not just a single company. Because of this, the benefit to the industry and society as a whole is likely to come much sooner than with many small patents by individual companies. Because of the faster timing, the present value of the benefit of the combined research is likely to be higher than the sum of the present values of the independent research of the individual companies. The cross-fertilization of the combined research programs may also provide benefits. Anti-trust laws do not permit companies to work together in this fashion, without some federal program.
What are trends in well productivity?
One exhibit prepared by ARI shows declining well productivity.
Part of this decline in well productivity will be offset by the recent lower cost of drilling wells, because of efficiency gains. Some of it is expected--companies are now drilling more closely spaced wells, each draining a smaller area. The lower well productivity does makes it more difficult to maintain profitability, however.
How is profitability of the unconventional gas industry viewed?
Figure 11 shows a recent profitability analysis by Goldman Sachs. It seems to indicate that the profitability of gas projects (nearly all unconventional) which are now underway is acceptable. Production of unconventional gas is viewed as low risk--the gas is easy to find; the trick is extracting it without losing money. Profitability is not expected to be as high as for some other types of ventures, because of its low-risk nature.
What are the prospects for unconventional gas going forward?
ARI shows this chart of its view of reserves and technically recoverable resources.
ARI characterizes the amounts it shows as merely a "snapshot in time" of its view of how much can be technically recovered, based on what is known about reservoirs today and current technology. ARI says its estimates are sometimes considered "aggressive". ARI has been making estimates of this type for several years, and their estimates have been trending upward. It seems to me that there is a reasonable possibility that ARI's estimates will prove to be accurate, or even low, with improving technology. They seem to have a good understanding of the industry, and the approach they use seems reasonable.
The third layer from the top of the pyramid is the amount ARI estimates to be technically recoverable, but that is not yet included in proven reserves. This layer totals 580 trillion cubic feet. The footnote indicates that 260 trillion cubic feet (of the 580 trillion cubic feet total) is estimated to be economically recoverable at a price less than $5.00 a thousand cubic feet; 140 trillion cubic feet is estimated to be economically recoverable at a price between $5.00 and $6.00 a thousand cubic feet; and 180 trillion cubic feet is estimated to be uneconomic at a price of $6.00 a thousand cubic feet. The current price is over $11.00 a thousand cubic feet, so some of the uneconomic layer may now be economic. Of the 580 trillion cubic feet of technically recoverable resources, ARI indicates 379 trillion cubic feet, or 65% of the total, relates to tight gas.
Other organizations provide estimates of technically recoverable unconventional gas resources using older data. In 2003, the National Petroleum Council put together an estimate using data through 1998. Its estimate, comparable to the 580 trillion cubic feet, was 206 trillion cubic feet. The USGS in 2006 estimated the amount of undeveloped continuous resources to be 306 trillion cubic feet.
How do the reserves and technically recoverable resources for unconventional gas compare to recent US natural gas production?
The pyramid in Figure 12 shows 105 trillion cubic feet of proven reserves for unconventional natural gas as of December 31, 2005, (second layer of pyramid). This level amounted to a little over half of US total proven reserves of 204 trillion cubic feet as of that date.
The latest date for which proven natural gas reserves are available is December 31, 2006. Proven reserves were then 211 trillion cubic feet, based on EIA data. Natural gas production for 2006 was 18.5 trillion cubic feet, so proven reserves amount to about 11.4 years of production. These are the published amounts, without consideration of future "resources".
In Figure 12, ARI's estimate of technically recoverable, but not necessarily economically recoverable, unconventional natural gas resources as of December 31, 2006 was 580 trillion cubic feet. If we add this full amount to the proven reserves of 211 trillion cubic feet as of the same date, we get 791 trillion cubic feet of possibly available resources. 791 trillion cubic feet amounts to a little less than 43 years of production at the 2006 level. If we include only the 400 trillion in resources estimated to be recoverable at $6.00 or less per thousand cubic feet, the total is 611 trillion cubic feet, or 33 years at 2006 production levels (for all natural gas, not just unconventional).
Clearly, if these resources are available, it could make a big difference to the amount of natural gas which can be produced going forward.
Where are we headed going forward?
If peak oil is approaching, the price of oil is expected to rise going forward. The price of WTI oil is now over $120 dollars a barrel, and many are talking about oil at $200 a barrel in the next year or two. If natural gas follows its historical pattern, its price will tend to rise as well. One might argue that the price of coal will hold the natural gas price down, but with all of the concern about global warming, and all of the electrical power plants that use natural gas, I think there is a good chance that the price of natural gas will tend to rise with oil, especially in North America. Higher prices will tend to make more of the unconventional natural gas economic.
Improvements in technology have clearly made a big difference in the amount if unconventional gas that can be recovered economically. With the slowdown in spending on research, technology improvements are likely to be smaller, but there will still be some improvements. It is unfortunate that the recent energy bills have not included funding for combined unconventional natural gas research, similar to that done by the Gas Research Institute. Even if 100% of the funding were from the industry, it would be beneficial from the point of enabling research on a combined basis, so that society could get the benefit of the research more quickly.
Discovery is not really an issue with unconventional--we already know pretty well where the resource is, and tools are available (or are being perfected) to find the sweet spots. The industry complains that there are considerable problems in actually trying to develop the resources. According to a presentation by Laramie Energy at an EIA conference, one problem is speculators who lease land with no intention of developing it. Another is the fact that 50% of Western land in owned by federal or local governments, and cannot be developed. Another issue is the numerous permitting requirements which delay production. There are also many restrictions because of endangered species, surface use restrictions, and local ordinances.
We hear the oil industry complaining loudly about access issues. I think they may really have a point; it can be very difficult to get access to the land where tight gas is located and take the necessary steps to produce the gas. If some of these access issues can be resolved, this too will help natural gas production.
Whether on not unconventional natural gas production will grow in the future will depend on price, technology, and access. Liebig's Law of the Minimum may also play a role. While we often write off US natural gas, it seems like there is at least a possibility that the unconventional natural gas will make up for the decline in conventional natural gas. The rise in unconventional natural gas production may even permit a small increase in total US natural gas production, and reduce the need for imported LNG.
US natural gas production in 2007 was at its highest level in since 2001, and 2008 production is starting off the year higher than 2007. While no breakdown is available into conventional / unconventional, it is pretty clear that it is unconventional production that is giving the production boost. Natural gas proven reserves have been rising for several years. I think that production of unconventional natural gas is something we need to be examining more closely. The EROEI of unconventional natural gas is not very high, but there is a huge amount of it.
Gail
Many thanks for this informative and well-researched study.
The question really is, how much time will this unconventional gas give us on the 'Red Queen' treadmill before we slip off of it? Does this mean that home heating or electricity shortages are no longer in our 5 year horizon?
As you implied, the problem is the number of wells that we have to drill. For example, Texas natural gas production, from gas wells, in 2006 was the highest we have seen since 1981, but it took more than twice as many gas wells in 2006 to produce the same amount of gas that we produced in 1981:
http://www.rrc.state.tx.us/divisions/og/statistics/production/ogisgpwc.h...
I think that the fourth quarter of 2007 was the real start of the permanent energy boom/crisis. Whether it is a boom or a crisis depends on what side of the producer/consumer equation that one is located on. The industry can and will make money from exploiting smaller conventional oil and gas fields and from exploiting unonventional resources, but the question is whether we can increase our total net energy output, especially with personnel and equipment constraints.
Gail:
Thanks - this is really helpful in putting things in perspective. If I can tie into Westexas comment about the number of wells that it is now required to maintain production rates, it might be informative, when you make the trip, to ask API about the current lifetime of the wells that are coming on line, the decline rate and the percentage that are economically successful.
I think Liebig's Law of the Minimum is likely to be a big issue also. These facilities are out in the middle of nowhere. Food and water need to be trucked in, I am guessing. Replacement parts will often come from overseas. I wonder how long the whole complex operation can be held together once oil supplies begin to decline, and we run into increased financial difficulties.
Don't forget the renewable methane resource - biogas. It is a mature technology, already in operation throughout the world.
I doubt that biogas has the potential to replace more than a fraction of our present non-renewable methane use. Nevertheless, it can provide us a floor to which we can level off once the non-renewable methane resources decline in earnest.
Biogas could surprise. I read, somewhere, there are 100 million cattle in the U.S. I don't know how many would be available for manure recovery, and anaerobic digestion, but I'm guessing the number is significant.
Of course, there is, also, landfill, sewage, and opportunities to utilize dedicated crops for biomass as is being done in Germany.
We're going to be on this little planet for a long time (we hope,) so it seems to me that it just makes sense to use as many renewables as we can.
We're working on this now in BC. Our first projects are using cellulostic feed stock (wood waste from saw mills), but this is a limited source. The process is being optimized for each feedstock source such as sugarcane waste, municipal organic waste, or sewage sludge.
However, our process is different in that we don't require gas scrubbing or the FT process. More importantly, the gas is a good output, but the main product will be bio-char (charcoal). Once thought a nuisance output (until I got involved), the oil outputs will have great applicability.
The light fraction is equivalent to #2 Heating Oil, the heavy fraction might be blended with Bunker C, or used in road paving, etc. BC has a large ferry fleet (larger than the Canadian Navy) and using this fuel will go a long way to help meet the renewable fuel mandates set out by the provincial government.
Still I advise extreme caution about the volumes that can be produced. We have to be careful about maintaining sustainability. Yet, this process might allow us to make a soft landing if we can power down and turn the corner.
Very cool.
Coal bed methane has a lower heating value so it must be mixed with a higher grade gas brfore it be sold. Also the wells tend deplete faster so drilling wells is a continual process.
It's true that CBM is very pure (better than 98%, IIRC). As you state, this means it has a lower calorific value than regular natural gas, not to be confused with Lower Calorific Value (grin). This doesn't mean it's not marketable. My domestic gas bill is quoted in megajoules, not cubic feet, meaning the gas supplier corrects automatically for the calorific value and the customer pays for energy received. So that particular problem has been solved.
Another thing to take into account is the Wobbe Number, which is a function of upper calorific value and density http://www.sizes.com/units/wobbe_number.htm - as described it is not a dimensionless number. According to the website, methane falls right in the middle of the Wobbe Number range for commercial natural gases in the United States. IIRC the gas from the Morecambe Bay field (offshore UK) had an out of spec Wobbe Number and had to be blended with nitrogen before it could be put into the National Grid.
If you change to a gas of dramatically different specification then you may have to change the burner tips to avoid flame blow-out. This happened in the UK in the late 1960s with the switchover from coal gas to natural gas ("High Speed Gas"), and was a huge logistical effort, though the world doesn't appear to have come to an end as a result. If the gas goes to a single large user (like CO2-rich Miller Field gas in the UK) then it's simpler.
I understand that one cannot just import any LNG and expect to use it, because of differences in gas around the world. Our appliances in the US are tuned for one specification. Different ones are used some other places.
Typing natural gas pipeline specification into Google led me to this interesting paper - see Page 4 http://www.beg.utexas.edu/energyecon/lng/documents/CEE_Interstate_Natura...
It mentions gas turbines as one end use that is sensitive to changes in fuel specification, for example with LNG. This is because GT burners run a lot hotter and therefore nearer to the thermal creep limit than most end uses of natural gas.
Natural gas, being a natural product, has a variety of compositions.
Mostly it is methane (CH4) but can have various amounts of propane, butane, and ethane (2CH3 + XCh2) plus non-combustibles like N2, CO2, and He that cost various amounts to remove.
Trying to meet market specifications can doom a gas field economically. Nitrogen is especially expensive to remove with little co-product value, unlike helium.
That resource pyramid is just insane: undiscovered and unassessed? Without exploration drilling what is their model for the resource? All rocks of similar type have gas? This is most likely in the same vein as the USGS report from 2000 that was using a trivial statistical model to predict vast oil reserves off Greenland. Basically nothing more than wishful thinking.
I remember reading that in Canada there are vast tight gas reserves. The gas in Canada is much harder to extract than the tight gas in the US, but it totals several times the Worlds conventional natural gas reserves. The next great challenge?
There are tight gas resources around the world. Other than the US, I don't believe that much has been done with them, because other natural gas that was easier to extract has been available.
This is an exhibit from the National Petroleum Council's Facing Hard Truths report showing an estimate of the amount in place (not economically recoverable).
I don't know anything about how difficult Canadian tight gas reserves are to extract. US tight gas reserves were considered impossible, before a lot of research was done.
Regarding Canadian resources, AJM Petroleum Consultants from Calgary has good online pdf's (www.ajma.net then click on "about ajm", then "news and events", then "past presentations"). Also try www.rdfuture.com and click on "natural gas" and scroll down to the 5th graph. In general, AJM is predicting very expensive times ahead for Canadians and their cold climate. And the Canadian Society for Unconventional Gas indicates (if memory serves) that coal bed methane could only make up about 10% of the shortfall by 2020. I got to thinking a lot about this in February when windchill temperatures got down to minus 50 celsius just north of Calgary.
If nothing else, unconventional takes a long time to ramp up. Besides the infrastructure for the production, one needs the pipelines to take it to the users.
Some new US pipelines have become available in the last year. I think that is part of the reason for the increase in production.
Gail
I can't find the link to the site I found this info on. As I remember the problem had something to do with the holes bieng smaller than in US basins, and more difficult to fracture. They expected progress to be slow but the potential resource is immense.
The Wiki NG article on Canadian 4.1 Unconventional gas mentions the "Deep Basin" in Alberta as a massive source of tight gas; maybe that's the one? Low permeability. Dave Cohen's piece Canadian Gas - Decline Sets in likely has more info on tight NG.
Hi diss,
Those YTF ("Yet To Find") numbers are based on things like proven reserves per square kilometre in basins of known age and geological character, like the ones shown on the maps in Gail's posting, adjusted for track record in areas already explored. It's true that they are not precise, but that doesn't mean they are just pulled out of the air. A good explorer should be able to quote central estimates and error bars (traditionally P10-P50-P90).
It's not the case that all rocks of similar type have gas, but a given association of mature source rock, reservoir rock and seal ("hydrocarbon system") has a nonzero probability of containing producible hydrocarbon of a given type. That probability can be estimated from drilling history, in the same system or analogous systems if necessary, and the areal extent of the system can be mapped in a variety of ways. Subtract proven reserves and you've got YTF. You can do this with well penetrations or without - in the latter case, the error bars are larger, but not infinite.
If that YTF estimate was done bottom-up, i.e. by aggregating the estimates for a large number of basins and plays, then it could be quite accurate, even if the individual estimates are way off. Something to do with this http://en.wikipedia.org/wiki/Central_limit_theorem
How do you think oil companies decide where to explore, where not to explore, and when to stop exploring in a given basin?
Any chance they'll find some oil by the by?
Find some oil? Sure, all the time. Enough oil? That's a different question, as I'm sure you know.
If they are using actual drilling data then they do have an empirical model to work from. It is not clear from the various articles whether the yet to find reserves are associated with existing fields or are, like for Greenland, pulled out of the air.
Hi Diss,
Undrilled or sparsely-drilled basins are obviously more difficult, and this should be reflected in the P10-P90 range - which may include zero as a lower limit, meaning non-zero probability that the basin is barren for any of a dozen reasons. In the case of Greenland you would be able to work from analogy with the Jurassic and Triassic of the North Sea. It was the same basin before the Atlantic opened up, though the subsequent geological history would be very different - thermal history affecting hydrocarbon generation, and tectonic history affecting trap creation and destruction. You might have some approximate mapping from coastal outcrops and regional seismic.
It isn't a cookie cutter - every basin is unique, and the available data vary widely in type, quantity and quality. So does the amount of time and detail that you can put into the exercise. As you say, the popular press rarely bothers to mention this important fact.
Unconventional is fairly different from conventional with respect to estimation.
With conventional, one is trying to figure out whether there are fields available which have natural gas (or oil) that can be extracted in the conventional manner. These are discrete fields, and the world has been pretty well explored. It is difficult to find them. This is the reason why we are told that we are discovering less oil each year than we are extracting.
With unconventional, we know fairly well the extent of rocks in place which have natural gas trapped inside of it. I showed a map in Figure 7 for tight gas. Some places will have more sweet spots than others, but for the most part the resource is there. It has already in some sense been discovered, but it doesn't yet pass the proven reserve test.
As I understand it, the amount that is included in proven reserves is the amount that is located in areas which can be drained with existing wells, or has been specifically surveyed and tested. The area nearby in the same formation, which we have every reason to believe is similar to what has been fully surveyed, is "undiscovered".
Advance Resources International is a consulting firm that specializes in unconventional natural gas. They have an amazing amount of material up on their website. This is a link to a document that describes how they derive their estimates.
Thanks for the links and the explanation. Reading the second link the undiscovered category is really the uncertainty in existing plays. The unassessed resources, which have a volume comparable to the undiscovered in the pyramid figure, look like a stab in the dark.
Oh yeah, just speculating on finding the odd Black Swan while they turn the countryside into a pincushion.
The unconventional gas is very expensive to extract and prone to cost overruns when things don't work out.
This is an observation from the field and not the office. At times the pay-back if things don't work out could be in 5+ years !!!!
Correct, and for this reason it's a good idea to run a pilot before committing to large-scale development. These pilots can be quite big - multiple clusters of 5-10 wells each, to allow you to debug your completion design and data acquisition, and to give yourself a chance of hitting a sweet spot and some average reservoir. Then you have to operate the thing for a few years to quantify decline and interference (and dewatering rate in the case of CBM or shale gas) before making the final decision.
I've been wondering how rising oil prices will impact drilling - at what stage will it become unprofitable? Unfortunately in EROI on the Web part 2 of 5, (Provisional Results Summary, Imported Oil, Natural Gas) Charlie states that
“There is no readily available literature either on, or by which, one might derive the Energy Return on Investment (EROI) of Natural Gas. Published summaries of natural gas reservoir studies and general overviews of drilling practices are sparse. Even with such a broad study, it would be difficult to assess natural gas production generally because each kind of operation is very field- specific".
Not only is the EROI site specific, it is changing over time, if changing technology is playing a big role. I know John Freise has been looking into the EROI issue. It would be interesting to see more work done in this area. It is clear EROI is not very high. But can it be made high enough, in enough areas, that we can live with it?
I think the problem with cost over-runs is the reason why these sites tend to ramp up very slowly. There is a need to test whether what is being done is working correctly, and figure out ways to improve it to make it economical. Problems with extraction are likely, when one is right at the edge of what can be accomplished technologically, in an economical way.
Arthur Berman of World Oil has written a fair amount about Barnett Shale, and its profitability. He says that at last year's prices, most of Barnett Shale wells were not profitable, because decline rates were higher than what natural gas companies were expecting. I think the question then becomes whether some of the problems can be fixed with improved technology, and whether higher natural gas prices will help pull the wells up to a profitable level. If the answer is "no", we will see companies pull out of Barnett Shale, and whatever other unconventional natural gas plays are not really economic.
Which could take us right off the NG treadmill, unless the Gov steps in to subsidize drilling.
Incidentally I suppose Leanan or someone posted here about Chesapeake Energy Swings To 1Q Loss On Hedging Losses, about them pulling out of the Woodford Shale.
Interesting! We should be keeping a watch for these kinds of things.
My impression is that shale gas is generally a step below tight gas on the EROEI ladder, since it was later to develop and the amount produced has been smaller. It is possible, though, that there is enough variability among sites that this generalization doesn't make sense.