Readers have been asking questions about a couple of shale oil articles recently. One is an AP article called New drilling method opens vast oil fields in US. A similar article is a CNBC article titled Massive New US Oil Supply – ‘Peak Oil’ Fears Overblown? Both of these articles talk about the extraction of shale oil in the Bakken and other locations, using horizontal wells and hydraulic fracturing.
According to the AP article:
Companies are investing billions of dollars to get at oil deposits scattered across North Dakota, Colorado, Texas and California. By 2015, oil executives and analysts say, the new fields could yield as much as 2 million barrels of oil a day — more than the entire Gulf of Mexico produces now.
This new drilling is expected to raise U.S. production by at least 20 percent over the next five years. And within 10 years, it could help reduce oil imports by more than half, advancing a goal that has long eluded policymakers.
There are several questions that might be asked:
1. Is this really a new drilling technique?
2. How likely is the 2 million barrels a day of new production, and the 20% increase in US production, by 2015?
3. Can this additional oil supply really reduce the US’s imports by over half?
4. How much of a difference will this oil make to “peak oil”?
Let’s take the questions in order.
1. Is this really a new drilling technique?
No., this is not really a new drilling technique. According to Wikipedia, hydraulic fracturing was first used in the United States for stimulating oil and gas wells in 1947. It was first used commercially in 1949. Directional drilling, including horizontal drilling is almost as old, but it was not widely used until down-hole motors and semicontinuous surveying became possible. The techniques have gradually been refined, as oil and gas companies have used them more and supporting technologies have been better developed.
A major reason we are using these techniques is because much of the easy-to-extract oil has already been extracted. Horizontal drilling and hydraulic fracturing are more expensive, but can be used to get out oil that would be inaccessible otherwise. The hope is that oil prices will be high enough to make these techniques profitable.
2. How likely is the 2 million barrels a day of new production, and the 20% increase in US production, by 2015?
That is a good question. There is certainly a lot of drilling for oil being done now. According to Baker Hughes, 805 rigs are now involved in oil drilling. This is above the oil rig high point in 1987. (Natural gas rig counts are down recently, so much of this rig count increase seems to represent a re-purposing of rigs.)
Figure 1. US Active rigs engaged in oil drilling, according to Baker Hughes.
Active rigs in North Dakota have also increased greatly. (These rigs are include both oil and natural gas, but with the Bakken and Three Forks-Sanish plays in North Dakota, it seems as though most would be oil rigs.)
Figure 2. Active drilling rigs in North Dakota, according to Baker Hughes.
There are several reasons why the hoped for increase might not be realized, however. These include:
Inadequate infrastructure. One question is whether inadequate infrastructure will prove to be a roadblock to meeting ambitious production goals in five to 10 years. The AP article quoted above mentions that currently oil is being transported to market by rail and truck, and drilling companies have erected camps for workers. If infrastructure problems are already being reached, before the ramp-up really takes place, a person wonders how much of an obstacle these considerations will be in the future.
Inadequate price. What tends to happen when there isn’t adequate transportation for the oil is the selling price of the oil tends to be depressed, relative to other types. As of February 8, the spot price for Brent was $99.25; the spot price for West Texas Intermediate (WTI) was $85.85, and the spot price for North Dakota Sweet was $65.61. The target discount rate relative to WTI is quoted as being 10% (because it is a light oil), but the actual price seems to be much lower.
It is easy for operators to assume that the price differential will get better, and also that the prices of other types of oil will continue to rise. But all of these things are by no means certain. High oil prices tend to send the economy into recession, so world prices may not rise as much as hoped–they may oscillate instead, rising, then putting the economy into recession and falling again. Also the differential of North Dakota types of crude to Brent may stay low for an extended period, if infrastructure issues cannot be worked out.
Optimism before drilling. There are many unknowns before drilling including how quickly oil production from individual wells will decline, how long wells will prove to be economic, what proportion of wells will have high production, and the level of oil and gas prices in the future. It is natural for those who are trying to get others to invest in these ventures to base their assumptions on an optimistic view of the future. If experience with shale gas in Texas is any clue, once realities start setting in, the level of drilling may decline, and overall production, after an initial run-up, may decline. If this happens, it will be very difficult to meet the ambitious goals presented.
Figure 3. Texas natural gas marketed production based on EIA data. 2010 estimated based on Jan-Nov actual data.
Large amount of increase required. If we look at a graph of countrywide US oil production, it has been decreasing prior to an uptick in 2009 and 2010. Bakken oil production (in ND +MT) is shown near the bottom of Figure 4. It appears as a thin blue line that was a bit thicker back in the late 1980s, became thinner for many years, and now is a bit thicker (reaching an average of about 370,000 barrels a day in 2010). Getting that line, or that line plus some other areas that are only starting up, to increase by 2 million barrels a day, to 2,370,000 per day by 2015, would be a tall order.
Figure 4. US crude oil production, with North Dakota and Montana production separated out.
Likely other declines at same time. US crude oil production has been headed downward for a long time–actually since 1970, not just since 1985 shown on the graph Figure 4. If overall production is to be increases by 2 million barrels a day by 2015, it will be necessary to overcome these declines, as well as add 2 million barrels a day of new production. What happens is that each year, more and more oil fields and oil wells within oil fields become non-economic. These are closed. Also, what is extracted is an oil-water mix, and the proportion of oil tends to fall over time. This means that if a given volume of oil-water mix is processed from a well, each year the well will yield less oil and more water.
There has been discussion of raising taxes on oil companies. Raising taxes on oil companies tends to raise the number of wells that are non-economic.
Figure 5. EIA graph of US wells by production grouping.
According to Figure 5, about 85% of US wells are now producing less than 15 barrels a day, and about 15% of wells are moderate rate wells, producing 15 to 1,600 barrels of oil equivalent a day. Only a small percentage are high rate wells. If tax rates increase, some of them will be closed. New wells will also become less economic, and some wells will not be drilled that would otherwise be drilled. So a person would expect an increase in taxes on oil companies to result in a step down in existing production. Many of the oil companies affected will be small–their only business may be a few wells producing less than 15 barrels a day. The amount of oil produced by so-called stripper wells is about 900,000 barrels a day.
Another area where there is risk of decline is Alaska. The Trans-Alaska Pipeline System is suffering from issues related to low flow and corrosion. Major upgrades to the system may be needed, including heating the line, to keep it operational. At some point, the amount of “fixes” to the Alaska pipeline will exceed the value to be gained from shipping the oil, and the whole system may need to be closed because of low flow. The current flow through the pipeline is 640,000 barrels a day.
3. Can this additional oil supply really reduce the US’s imports by over half, in ten years?
US oil consumption reached its maximum level in 2005. Figure 5 shows a breakdown into its major components.
Figure 6. US liquids consumed, divided into crude oil, net imports, and miscellaneous
The crude layer in blue is the same countrywide crude oil production as shown in Figure 4. The purple layer on the top is imports (minus exports), so net imports, based on EIA data. The layer I have called miscellaneous is everything else that goes into what is reported as “liquids.” Recently, the miscellaneous category has been about one-half natural gas liquids, one-quarter ethanol, and one-quarter “refinery gain”–that is the expansion that occurs when the US refines crude oil. The “miscellaneous” items are products that provide less energy per barrel than oil. Many people believe that these additional items have been included in “liquids” figures to make US oil production look like it is performing better than it really is.
Natural gas liquids. I am suspicious that quite a bit of the 2 million barrels a day of additional production by 2015 that is being forecast is not really oil. Instead, I expect it will be natural gas liquids. This currently represents about half of the “miscellaneous” layer in Figure 6. Natural gas liquids (NGLs) include propane, butane, and other gasses. It may very well that much of the recent increase in “oil” drilling rigs is, in fact, primarily for NGLs, since there has been a great deal of recent interest in liquids-rich gasses. In fact, some articles talk about the possibility of falling prices for NGLs, because of a possible supply-demand imbalance, if production of these ramps up.
An increase in NGLs would be of lesser benefit than oil, because it is not directly substitutable for oil, and is a cheaper product. Initially, it would mostly make home heating for those using propane cheaper, but then tend to drive NGL developers out of the market. Unless NGLs can cheaply be converted to higher priced oil products (and refinery capacity can be added quickly to accomplish this), it would seem like a drop in prices would quickly put an end to the NGL ramp-up.
Imports. Figure 7 shows a graph of US net imports–that is the top layer on Figure 6–by themselves. (On all of these graphs, the data for 2010 is through November, but I have estimated December, to give an approximate 2010 value.)
Figure 7. US net oil imports, based on EIA data.
It seems to me that oil imports really depend on what the US can afford for imports–how high the price is, how much oil for export is on the world market (which helps determine the price), and whether the US is in recession because of high oil prices. Oil imports were increasing up until 2005; now they are decreasing. This decrease in oil imports reflects the fact that oil in the world export market peaked in 2005, as much as anything else. High oil prices (and layoffs indirectly related to high oil prices) have made it difficult for people to afford goods and services that require oil in their production (vacation trips, new homes, new cars, many other types of goods). As a result, US demand for oil products has dropped to the point where our imports have dropped each year since 2005.
In my view, if additional US oil is produced, it actually helps increase US demand for oil products–in fact for all products. More people are employed, and this puts more money into the economy. It also helps keep world oil prices from escalating as fast as they would otherwise. The net effect is that I would expect higher US oil production to increase US imports (or maybe, keep imports from falling as fast), because they will help keep the US out of recession. I am sure some will disagree with me on this, however.
US oil imports have declined about 25% in the five years since 2005. In the next ten years, I would expect oil imports to continue to decline, regardless of what we do, because the amount of oil on the world market will continue to drop, and oil importers will tend more and more to be in recession. It is not clear how much US oil imports will drop, but a 50% drop in the next 10 years would not seem all that unlikely, regardless of what we what we produce, because of oil exporting countries will tend to consume more, and more countries will shift from being exporters to importers. We are currently importing 9.4 million barrels a day, so a reduction by half by 2020 would be a reduction of 4.7 million barrels a day.
Responding to the initial assertion that the oil ramp-up will permit a reduction by half of oil imports by 2020. If somehow over the next ten years, we could really produce 4.7 million barrels of oil to offset the decline in oil imports that we will likely be losing because of declines in the world export market, that would be wonderful. But at most, what it looks like the author of the AP article is looking for is a mixture of NGLs and crude oil that might ramp up to 2 million barrels a day by 2015, and 4.7 million barrels a day by 2020, in addition to compensating for whatever other declines we might be encountering.
If the mixture is heavily NGLs, it seems as though refineries will need to be reconfigured to adjust the NGLs to permit reformation into longer-length chains, to make the NGLs truly substitutable for oil. I do not know how feasible such a step would be, or what the “energy cost” would be. It would really be the net oil addition, after the conversion process, that would be of interest.
4. How much of a difference will this oil make to “peak oil”?
It seems to me that whatever additional oil and NGLs are produced will have a much bigger impact on the US economy than it will have on “peak oil.” Adding more energy, if it can be done at a price that is affordable, will be help keep the US out of recession, and thus keep employment up and demand for energy products up.
We have known for a long time that a huge amount of oil is available, in forms that are increasingly difficult to extract. The question, in my view, is how much of this huge amount of oil is economic to extract. This is closely related to Energy Return on Energy Invested (EROEI). At some point, oil becomes too expensive to extract; it just puts the economy into recession, or worse. A schematic diagram of what happens is shown in Figure 8:
Figure 8. Schematic diagram of economic and non-economic resources
We have known about the Bakken oil shale and the many other shales that have NGLs for a long time. There are also many other types of oil that we know about (such as ultra-deepwater, polar, oil-shale) that are quite expensive to extract, both in terms of price in dollars and in terms of resources required. The resources required are not just the direct resources of drilling–they also include pipelines that might not be used for very many years, and even local refineries, which again might not be used for many years, and training for workers. With respect to NGLs, if they are to be used as “regular” oil, they will need unification, perhaps with catalytic reforming, if they are to be used as longer-chain hydrocarbons, which are the higher-priced, more desirable, product. The big question is whether these processes can be made to be economic. If we ever get to the point where more energy is consumed in these processes than we get out at the end, the processes are clearly losers.
To me, each decision to drill a new well, or to start a new field, or even to continue pumping from an existing well, is based on the economics of the day. Some fields or potential wells or new wells drop below the “Non-economic” line on Figure 8, as tax rates rise. Others rise about the non-economic line, as technology improves. But by and large, the vast majority of oil resources that we know about will forever lie below the non-economic line. The assumption that oil prices will rise high enough to allow us to extract all of these oil sources is based on an incomplete understanding of the situation. At some point, the costs (and energy demands) of extraction and processing just become too high, relative to the benefits. Demand can never rise high enough to produce the high prices required for extraction. Ultimately, production will fall, not from a lack of resources, but from inadequate demand for high-priced oil from low quality resources.
The manner in which Figure 8 fits in with Hubbert’s Curve is not directly obvious. Most “liquid” oil will tend to be in the upper “economic” triangle. Most “solid” forms of oil will tend to be in the bottom portion of the triangle. (Hubbert’s Curve is usually applied only to the liquid portion of oil resources.)
But within this general breakdown, the edges will be determined by economics–does it make financial sense to use a particular tertiary recovery method on a particular liquid-oil field? Is it economic to extract something that is not quite liquid oil (like NGLs) and transform it to something that might operate vehicles?
One thing that is definitely different about Figure 8, compared to Hubbert’s Curve, is a different implication regarding how much is left, when the non-economic line is reached. Hubbert’s Curve discussion talks about half of the oil being gone, when decline starts. There is no such implication with Figure 8. Operators will continue to extract oil that can be extracted at low price (high EROI), even as more and more new types of extraction fall below the non-economic line. But it seems quite likely that much less than half of the low-priced (high EROEI) oil will be left, when we start running into difficulties with new oil types falling below the non-economic line.
To me, the big question is whether Bakken oil shale, other oil shales, and all of the additional NGLs can really be made economic. If they can, and the amount of oil extracted raised to the hoped-for 2+ million barrels a day by 2015 and 4.7+ million barrels a day by 2020, the new oil sources may help to keep recession away for a while longer. But if not, we are likely nearing the point where limited oil supply will push us more and more into recession. I am doubtful that the new oil shale sources can ramp up as quickly as hoped, but there is at least some glimmer of hope that these fuels will help keep the day of reckoning away a bit longer.
Let me start by saying that I really enjoy your articles on The Oil Drum, and I am also just starting to explore this excellent site. The present article is especially interesting. However, I would just point out one mistake in the article, where you write the following:
I fairly certain that you already know that the Eagle Ford play is located in south Texas, and not North Dakota, as the statement above implies. A very minor flaw in one of your typically superb works of analysis.
Thanks. I meant the Three-Forks-Sanish formation, which lies under the Bakken. I will fix it.
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I was watching the Keiser Report.
(http://rt.com/programs/keiser-report/money-forest-oil-dictatorship/)
Greg Palast is a documentary maker and therefore someone of influence.
He said that the world is not running out of oil, but that the Oil Companies are winking and nodding to each other and holding the oil off the market. He further says that the most expensive oil is $30 a barrel to extract.
He says that the markup is great because of the artificial scarcity.
This is the position held by my son.
We politely disagree.
However this is the opposing view held by the majority.
I will not insult my reader by defending this view.
However can it be true that we are destroying the ecology of Canada in order to maintain the fiction of oil scarcity? Are we that perfidious?
It is amazing the stuff people can say and get away with. There are a lot of small oil companies. Are they all colluding too?
If you haven’t seen Gasland yet, I recommend it.
http://www.imdb.com/title/tt1558250/
One of the nice things about dealing with North Dakota is that the state does a nice job of publishing production statistics online.
I haven’t got time to look at the details, but here are two points to consider: firstly, the spacing for the new horizontal Bakken wells is generally 1280 acres, or one every two square miles. The whole of North Dakota is a bit over 70,000 square miles and the Bakken only underlies about a third of it, say 25,000 square miles. Enough space for 12,500 wells. Secondly, these wells aren’t producing nearly what some people are claiming.
In December 2005, 3,241 wells produced about 107,000 barrels of oil. In December 2010, 5,097 wells produced a bit over 340,000 barrels of oil. Probably most of the additional wells — there are at least at least 1,856 of them, and that’s assuming every well producing five years ago is still producing — are horizontal wells. Now if there are this few horizontal wells, and the average production of the oldest 3,241 is still 33 barrels per day, the average production of the new wells is only 125 barrels per day. With this average production, assuming no dry holes, all the horizontal well locations in North Dakota might produce a peak of about 1.6 million barrels per day. That could conceivably be reached by 2015 if the infrastructure problems were solved. But I’d give it no more than a 10% probability even then.
I am sure that the people drilling wells now are hoping their wells will do better than the previous ones. But the fast decline rate is a problem. And someone has to come around and service all of those wells for an awfully long time, it they are really to last, say, 40 years. I don’t know exactly what they are quoting, but it is a long time.
Flaw in the calculation:
It postulates 1 well per 2 square miles is held constant.
If they dense them up, then your 12,500 multiplier goes up.
We need data on production decline rate from the 2005 wells.
All the information is on the NDICDMR website. I don’t have the time to go through it now, but I have looked a selected areas in the recent past, and the decline rates are quite sobering.
The wells we are talking about have at least one two-mile horizontal section. It is difficult to see having more than one of them in an area two miles by one mile. There is some possibility of additional wells to drain other horizons, but most of the wells are drilled vertically to the Bakken, then deviated to go horizontal following a thin, slightly sandy layer in the middle of the shale.
Calculations of the amount of oil which could have been generated by the Bakken as a source rock range from about 50 billion barrels to about 400 billion barrels. The high value is almost certainly too high, and the low value is probably too low. But much of this oil may have escaped to the environment in the millions of years since it was generated, some may never have been generated because in some parts of the basin the Bakken may never have been buried deeply enough.
Regardless of how much oil has been generated we still have to consider recovery factor. Estimates for primary recovery range from 3% to 50%. As this is an unconventional, tight reservoir, I’d think 3% is quite a likely value. The best reservoirs ever found rarely have a recovery factor as high as 50%, even after everything known to reservoir engineers has been applied. You might recover 20% eventually from the Bakken, but I wouldn’t put any of my money on it.
Thanks for the link. I probably should have gone more into the Bakken particulars, but the post was getting long as it was. It is awfully easy for those who are selling the idea to investors to give overoptimistic views of what will happen in the future.
Another great post Gail. Thanks for the good work. I would like to pont out that the USA also imports virtual oil via importing goods so our actual use is perhaps 10% higher than what it looks. China actually uses more energy/emits more carbon for the production of many items than would be the case if they were made here more efficently but for the fact that the pay rate here allows the worker to buy more energy, more than swamping out the efficiency difference. The US trade deficit in steel and iron was $11.7 billion 4 years ago. This trend of virtual imports may continue.
Agreed. Also, China’s primary energy source for manufacturing is electricity from coal. It is a very cheap source of electricity, so with the low wages, it makes China very competitive.
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“There are several questions that might be asked:
1. Is this really a new drilling technique?
2. How likely is the 2 million barrels a day of new production, and the 20% increase in US production, by 2015?
3. Can this additional oil supply really reduce the US’s imports by over half?
4. How much of a difference will this oil make to “peak oil”?”
Are these really the questions we should be asking?
How about:
1. Should we burn up another two years of gasoline in our tail pipes via shale oil and gas so that we can shuttle the kid to soccer and make energy capitalists rich, even though that last two years of BAU will trash the aquifers in the country and ruin the resource base, making it unlivable, a la Gulf of Mexico?
We need to consider our choice of questions more carefully than our answers.
It seems as though we will just keep on doing what we are doing until we cannot.
The yeast have found some low grade sugar.
This will keep their production of alcohol (pollution) going on for a while. But the merry carbon dioxide bubbles will slow right down to a stop.
I can think of two ways to get the party going again.
1 We consume a different sort of energy. (and we end up with a different economy) but eventually
2 We have to break the bottle. We have to go off-planet. No excuses.
The sooner we start on this the better our chances of success. This is not rocket science. It is blindingly obvious.
Sniffing the breeze, I think that this is the thrust of thinking at higher levels. They are doing their geological explorations in space now.
Whichever nation colonizes L1 or L2 first will be the gate keepers to the ultimate prize.
The cosmos itself.
I hope you are joking about going off-planet. This is crazy!
I have come to believe that the game is over. Technology is in decline and has been since the 1970s oil shocks.
In 1492, Columbus made his first trip to the New World. Care to guess the date of the first permanent European settlement / city following him? 1 year later. 1493. Hispaniola has had Europeans living there that long.
Our first trip to the moon was 1969, and then for good measure 5 more trips were made over the next 3 years. But when was the first permanent settlement on the Moon? Right, we haven’t been back for 42 years and all plans say it will be minimum 50. Repeat, we’re going to be AT LEAST half a century to even return to visit, and the truth is that won’t ever happen because oil scarcity will destroy civilization before any such chance.
It has occurred to me that this might be a law of the Universe. There cannot ever be colonization of a second or third or fourth planet because planet number 1’s resources can’t support both planet #1 and the colony for decades and decades while they “get on their feet”. Even a benign environment like Hispaniola required ongoing Spanish supply for decades to keep the colony going, to say nothing of a numerous supply of African slaves.
This may be a law of the Universe. It can never work. It’s why we get no space alien visits. There are no interstellar civilizations because they could not get started.
I always enjoy posts about leaving our home planet for the final frontier. I have a vision of us discovering some earthlike planet, collectively pooling our few remaining resources to get there; humanity’s last hope. After an epic voyage, our best and brightest successfully land upon their new home planet only to find it used up, hopelessly depleted and polluted, the few remaining original inhabitants laughing their asses off:
” You came all that way for this? The party’s over, but welcome!”
Gail,
I’ve read that the increase in optimism for tight oil is mostly due to the testing and use of new fracking chemistry over the past 12 months, which apparently thins the oil enough to permit an easier flow in low porosity rock. My guess is the base is similar to a dispersant – which would be kerosene. In gas fracking, the frac fluids, whatever they are, are evacuated from the well to a great degree before the gas is processed and released into the pipeline; with oil, I’ve no idea what is done with the thinner.
I suspect that pumping refined oil product into the ground to get oil out of fractured rock changes the already lower EROEI.
I hadn’t heard that about recent changes in fracking fluid. It seems to me that oil has more possibilities for improvement in production than natural gas right now. Fracking is terribly high priced relative to natural gas prices. For oil, at least the selling price is enough higher that the high cost of fracking can be absorbed into the price structure.
There is an oblique mention of it in thr AP story: “Because oil molecules are sticky and larger than gas molecules, engineers thought the process wouldn’t work to squeeze oil out fast enough to make it economical. But drillers learned how to increase the number of cracks in the rock and use different chemicals to free up oil at low cost.” The topic came up – for me – during an informal faculty discussion last month within our Integrated Energy department, since our (Garfield County Colorado) community college has a large oil and gas drilling focus (the new building was funded in large part by Halliburton, EnCana and Williams) and given the drop in gas prices, there has been a lot of interest in developing more liquids production.
Great post Gail (again) Thanks!
You wrote: “February 8, the spot price for Brent was $99.25; the spot price for West Texas Intermediate (WTI) was $85.85, and the spot price for North Dakota Sweet was $65.61. The target discount rate relative to WTI is quoted as being 10% (because it is a light oil), but the actual price seems to be much lower.”
At this moment (00:30 hrs in Madrid on 15 Feb) the price of Brent is $103.10 and WTI is $84.81 . What is your take on the growing difference between WTI and Brent? What’s going on here?. Thanks. – JS
I don’t quite understand it either, but it seems to be related to not being able to get the oil to the refineries down on the gulf coast. All of the Bakken oil with nowhere to go would seem to make the situation worse, since it is being trucked to Cushing. I see North Dakota Sweet closed at 63.48, about 62% of Brent price.
I don’t want to drift too far off the point of your excellent post, so I’ll limit this remark to the reference to this article – http://seekingalpha.com/article/249307-widening-of-the-wti-brent-explained-by-u-s-idiosyncratic-factors – which offers some explanation to the growing gap between WTI & Brent. I have to say (if only intuitively) this shift and growing gap “smells a bit odd”, given the timing and I’d like to get a better handle on what’s behind it. Certainly growth has more of a chance at $85 then at $103 and rising… You’ve always done a great job at digging into things and offering clear explanations Gail. (hint, hint;-))
Thanks for the hint. I’ll keep the idea in mind.
Another great article. I’ve wondered as we exploit these smaller finds whether there is local fuel needs that could be met with “smaller” pre-engineered refineries sited locally supplying gasoline/diesel/whatever to the local market instead of transporting crude out – I have read that “standard sized” refineries take 10 years of permitting before construction begins.
This is another positive for CNG, the plant to take advantage of locally available NG is a fraction of the startup in time and $’s. Some local islands of CNG transport fuels might be very efficient. Interestingly in Pennsylvania it is possible to buy farms with onsite NG wells that heat homes and outbuildings, of course this is not compressed.
There was a study done in North Dakota that said what North Dakota really needed was diesel, for all the farm equipment. The catch is the very light oil that is being extracted is not a very good match for this need. It is also unclear how long the boom will continue. Once the drilling stops, production is likely to start declining, almost immediately. Those considerations, plus the relatively low price available for ND oil and the fact that there is excess refining capacity elsewhere have discouraged building ND refining capacity.
A wheat farmer friend here in Western Australia was invited to a combine (Header) factory in USA. It could have been John Deere.
I told him to ask how they were going to run their headers without diesel.
He never got a response.
Thanks for the great analysis on Shale Oil.