Tech Talk - Gas Flares and Their Significance in Russia

Over the weekend I went to a talk on the promise of shale oil and gas given by Sid Green, a friend and one of those members of the National Academy with Washington influence in regard to the future of the fossil fuel business. (He appears much more a Yerginite than a follower of Matt Simmons, as was evident by his conclusion that the fuels from the shale deposits of the country will be our short-term savior.) This is a proposition to which I have provided some evidence of doubt. However, it was in his introduction by Joseph Smith, the new Laufer Chair of Energy at MS&T, where a slide appeared that is useful to preface where the Tech Talk series will go next. This is the slide:

A poster from NOAA showing the light emitted at night from city lights (white), fires (red), boats (blue) and gas flares (green). (The picture was put together over the period from January to December 2003.)

It was that large green blob sitting just below the Yamal Peninsula in Russia that caught my eye. It shows the volume of stranded natural gas in Russia that is being flared off because it is stranded, i.e. there is no current way to ship it to market.

Interestingly, given that preponderance of flaring in Russia, one can also go to a paper given at a Russian meeting where the more ubiquitous size of gas flaring operations around the world is more evident.

City Lights and gas flares around the world, data collected In 1994-95. (city lights in grey, flares in red).

As I noted in a recent post on developments in the Bakken shale, up to 30% of the natural gas that is being produced with the oil is being flared at the moment because there is no way of getting it to market. (And in 1994, note the amount being flared in the North Sea). It is not just a problem for large wells. For many years I drove between Rolla, MO and Crane, IN, spending the night in Vincennes, usually arriving late, with my drive through Eastern Illinois illuminated by flares from the small stripper wells along the way. And it is possible to see flares from the rigs operating in the Gulf of Mexico.

Gas flares illuminating the night in the Gulf of Mexico (NOAA)

In the past, Gregor Macdonald has also documented the flares that are found off the coast of Nigeria. And there was some suspicion that these represented the greatest volume of gas being burned off in this way.

Flares around Nigeria color coded by duration, Those active in 2006 and 2000 are yellow. Those active in 2000 but not 1992 or 2006 are green. Those active in 1992 but not 2000 or 2006 are blue. (NOAA )

A 2007 survey carried out by NOAA for the World Bank showed that Russia was burning roughly twice the volume of gas as that lost in Nigeria. A close look shows how the plumes from the flares dominate the Siberian night-time sky.

Thermal plumes from gas flares in Siberia

The NOAA report indicates that around 160 billion cubic meters of gas is flared each year, roughly a quarter of the volume of natural gas that is used in the United States each year. And while countries such as Nigeria have been able to reduce the amount that is flared, countries such as Russia, Kazakhstan, and Iraq have increased the volumes flared. (It also explains how the images above were generated). The region of Russia with the most gas flaring is that around the Khanty-Mansiysk region, which accounts for roughly half the Russian total. In 2007, a conference on the subject heard that Russia was flaring around 50 bcm per yer, with Khanty-Mansiysk contributing 24 bcm of this total. (The gas is flared because this is currently where about half of Russia’s oil production is coming from). At that time the goal was set that by the end of this year, (2011) some 95% of this natural gas should be utilized. There have been a variety of ways suggested to reach that goal. Again, putting the volumes in context, Russia commercially produced some 600 bcm of natural gas in 2006, as well as some 10 million barrels of oil a day.

Flaring around the Khanty-Manysiyski region south and east of Yamal. (World Bank)

At present Russia has reached a new peak in crude oil production of some 10.34 mbd for October, while Saudi production is estimated to have risen to 9.8 mbd. Russia is thus the current largest oil producer, and so it is time to look at where the oil is coming from (other than just the region shown above), and what the prospects for the future hold for the longer term production and export of energy from that country.

The natural gas production picture is not quite that rosy, even with the reduction in gas flaring that has been undertaken. Gazprom is reported to have reduced supply as prices in Europe have risen towards $15 per kcf (thousand cubic feet), almost four times that of gas in the United States. Russia as a whole produced some 1.8 bcm/day (63 bcf) of which Gazprom produced 1.35 bcm, both figures down from the same time last year. At the same time, domestic consumption of natural gas has risen by some 1.3 bcf/day. Russia supplies about a quarter of European demand, and as production falls off in some of the fields of Western Europe that portion may increase. However, the global supply of natural gas is still quite healthy with countries seeking to find domestic sources from the gas shales that might lower their import needs. Thus the power that Gazprom was able to wield just a couple of years ago has now been somewhat reduced.

All of these factors strengthen the conclusion that this series should now move to look at some of the fields in Russia, and given that Dr Yergin has proved to be a better historian than prophet, that probably means that I should go away and re-read The Prize, before it starts. (Though The Quest is an easier read). After all, one wonders how many of us, a week ago, could have found Khanty-Manysiyski on a map?

Location of Khanty-Manysiyski on a map of Russia (Google Earth)

In passing, Secretary Salazar has just announced that permitting will allow the Natural Buttes Project to move forward. Anadarko are expected to develop up to 3,675 wells in the Uintah Basin over the next decade to supply more cheap natural gas into the market, and likely keep the price pressure on the production of gas from gas shales. Which brings me full circle back to the opening of the post, since the question that I asked Sid at the presentation was “How long can the gas shale companies afford to sell their gas at under $4 per kcf, when it is costing them more than this to produce it?”

I had a short snippy version of Sid's reply here, but he was kind enough to send a critique and deeper explanation, which gives a better answer than initially drafted. To summarize his answer, he feels very much in agreement with the points that Rockman has been making in comments on a number of my posts on this topic.

He notes that financing for the E&P companies has recently largely come from "venture capital" money. The companies are able to recover much of their own capex in the first months, but he was careful to note that this did not imply that they are able to make a profit. And with that return they are able to continue on the “tread mill” of drilling another well, and another . . . .

He quoted costs, and noted that a recent WSJ article said that Pioneer was reported to have costs of around $2.48 per kcf. Though if I can interject they are drilling the Eagle Ford and thus the costs may be lower for the gas, since they are, as he notes, making most of the money from the associated liquids. (And Rockman is not that excited about the general situation down there).

However, he thinks Haynesville costs are up to $3.50 and Marcellus up to $4.00 or more per kcf. As a result the number of rigs might soon start falling, though he has hopes that with some technical improvements the cost figures might come under better control, and he senses that there are others in the industry also anticipating greater production at lower cost with some of the better ideas that are being developed. These relate (HO thinks) to better control of the fracture paths induced out into the formations. But without much change operations will move over to more liquid productive areas and the natural gas situation will not be sustainable as it is.

As an additional side comment, there are now animated maps of the Barnett, Bakken, and Eagle Ford plays, showing the wells drilled each year, and the production totals, under the Shale Play Development History Animations sections of the EIA map page. (H/t this weeks TWIP which is on the Bakken and Eagle Ford.)

When are Americans going to put volume based taxes on fossile fuel like anybody a bit civilized and caring just a little about their own future and little chance if any to get through ?

Good question.

I think part of the problem is the Oil Age started in the US and so it has become a cultural phenomenon, not just an economic one. As for coal, the existence of 80 thousand coal miners has something to do with it, in my opinion.

The amount of inertia in moving away from Coal is amazing and a testament to the strong relationship the Coal Industry has with Utilities. For example, Xcel Energy is a Utility in the Mid-west that has some of the best Wind resources in the World. Yet according to their website only 9% of their power is provided by Wind, with plans to have 20% Wind power by 2020. Xcel should have 20% from Wind today, not 9 years from now. This is why relying exclusively on the market doesn't always work -- there are many incumbent relationships in the marketplace actively working to defeat change for the sake of profits.

When the fossil fuel interests release their strangle-hold on our government, media, and public opinion.

IMO, the shale gas play is at least partly related to the broader attack on the solar and battery industries. Shale gas probably isn't sustainable, especially at current prices. But it may just last long enough to kill or vastly curtail the domestic solar industry which means 5-10 more years of sick profits and industry dominance. Of course, this could also be an amazingly huge over-reach and the public might call for VBTs or even resource nationalization after they see the prices hit the ceiling again. Hmmm....

Robert – I’m going to tease but don’t take it personally. I do understand where your comment comes from and won’t insult you by calling you just another conspiracy theory nut. But you are so wrong about the motivation of the vast majority of the fractured shale players. They are a desperate mob trying to justify their existence to Wall Street. They have no choice but to throw themselves at those plays as if there were no tomorrow. Because there won’t be a tomorrow for most of them if they don’t constantly replace their produced reserves. They aren’t drilling every location they can lease to hurt the alts. Today, and into the future as far as I can see, the alts are no completion to the oil patch. Just MHO, of course.

A side effect might be to keep ff low enough to inhibit alt development to some degree. I can see how that might lead you to your conclusion. But if you could get some national movement to ban fractured shale drilling you would have my support 110%. I drill for conventional NG (what little there is left here) and those public companies are bringing so much unconventional NG to the market it’s hurting our profit margin. In fact, that’s my new theory: the fractured shale players are actually trying to put us private conventional companies out of business. Yeah, yeah…that’s the ticket.

An economic interest creates a common natural interest. You say its a "desperate mob" but in the final analysis it is a group of motivated people with a common economic interest in promoting fossil fuels. Because a group of people participate in an industry because of an accident of geography or education doesn't change the effect of their behavior or its motivation.

The bottom line: This "mob" could be doing something else, liking promoting Solar or Wind. They have chosen not to do so. That's their decision and in the end they have to take responsibility for it.


To put some specifics re: the pressure on public companies to acquire positions in the shale plays. From a few months ago this was the premium BHP had to pay to gain additional Eagle Ford Shale acreage:

“BHP will pay $38.75 a share using cash and debt, the companies said in a statement today. That’s 61 percent more than Houston-based Petrohawk’s average price over the past 20 trading days and compares with the 25 percent average premium in 17 deals worth at least $5 billion for oil and gas producers in the past five years, according to data compiled by Bloomberg.”

The CEO of Petrohawk made $117 million on his stock position. Do you think he cared how profitable their drilling effort proved to be? Early on the word was on the street that Petrohawk’s business plan was to do just as they did. I reviewed several Eagle Ford deals. Knowing they wouldn’t accept the offer I proposed instead of giving them the cash I would use that money to pay for a share of the wells I would drill on their acreage. Thus making them even more money than they were asking. Not one of them took the offer. And these were the folks that understood the play better than anyone else. BTW: none of these companies were public…all privately owned like mine.


An additional comment on venture capital taking positions in shale plays through investing in PubCo’s:
Venture capital will take an equity position in a public company through a financing, not necessarily an IPO. (Financing an IPO is a different risk profile, although the investment strategy is the same). The venture capital group or groups then ride the stock-price up for a year or so and get out at an opportune moment, say, at least a doubling of the stock market value of their investment.
The venture capital groups are not necessarily in the stock at the end, when the shale gas-focused company is flipped to a major. If they do retain some equity in the company, say they sell half or three-quarters of their original position, then they receive an additional bonus when a big boy pays a premium on the 21-day average share price.
Venture capital will not necessarily take a position in a PrivateCo, because the stock is not liquid, it cannot be traded on AMEX or NYSE or ... don't get me started on NASDAQ, which is for suckers. So the venture capital cannot bail out of the stock in a hurry.
This is why Rockman's company "PrivateCo" has a different corporate strategy to the Pubco's, they are in oil plays for
(1) Cash Flow From Operations and
(2) building a Reserve Base of Proved Producing, Proved Undeveloped and low-technical risk Probable reserves. Note, not Potential Reserves or a big land position.
The shale gas play in the US and Canada is now a stock market play on Wall Street and Bay Street, not a gas play or an energy-content play. (It didn't used to be, it was a technology play to find out how to get the gas out of the Barnett Shale, coincidentally and fortuitously in the Fort Worth Basin near Houston and Texas oil money).
Would I do the same if I were running a Pubco with an opportunity to take a big land position in a shale gas play?
Of course, with my eyes wide open, knowing who the venture capital group was.
As the lady said, “Goodness, what lovely diamonds”.
“Goodness had nothing to do with it, honey”.

Sort of off topic - That nightime picture and all the lights. It struck me that we are focusing on the 'green' to have the 'white'. It would be interesting to see both the gas flares and the city lights rated in net energy. Not just the lights but the net energy to generate the power to light.

As stated the energy in those flares is not economic to transport at current prices. To expect rising prices assumes the ability to pay. I'm not so sure about that. To follow this further at what 'price' do we become Carterites? When do we turn off the lights and put on a sweater? We must be getting closer to that point.

I hold the belief that we are 'a herd'. That energy reduction(lights off) will come as an economic decision 'voted on' or forced upon the millions in their everyday decisions. Our collective decisions are greater and more determinate than any leader.

D - Not that far off. It's all about "waste". Of course, one man's waste is another man's job. It's easy to look at some city's wasted lighting. But systems resist change as a matter of self preservation. Eevn if the cost is illogical.

A good example: all flared NG could be captured but it would reduce profits. The trade off in the Bakken is the acceleration of oil production. If the states banned flaring the play would still be drilled but much more slowly. The NG pipeline system would expand as wells were drilled close to the existing infrastructure. As driling radiated out additional short p/l's would be added. From a long term perspective this should make sense. But again back to the side thread: public companies live quarter to quarter...they can't offer business plans focused 10+ years out.

"But again back to the side thread: public companies live quarter to quarter...they can't offer business plans focused 10+ years out".
Pubco start-up principals WILL be asked: "What's you exit strategy?".

...public companies live quarter to quarter...they can't offer business plans focused 10+ years out.

This is the problem, you know. And not just with energy stocks, but with all of them. And it is not the shareholders (Hell, some of them would love to see a 10+ year plan, since some of them want to invest and hold, not 'earn' their money by gaming the system. In fact, I would guess that MOST of them would. The reason we see what we do is that Directors and Officers of our Corporate Overlords 'earn' most of their compensation from stock options. The way these work is, say a company stock goes from $35 to $5 in a year. Well, the options given when the stock was $35 (typically at < $30/share, they hold in case the stock goes to $40 or so. With the stock at $10, they are issued options to purchase at $7.50. If the stock rebounds to $15 in the next year (usually they cannot exercise options sooner than that), they make $7.50/share, usually in the 100's of thousands of shares, and if the stock goes to $35, they really rake it in. And for what?

So, say you run an energy company as CEO, and this quarter your stock is valued at $5/share. two quarters later you want that stock to be at $7.50 or so... not hard to do with marketing PR spin and a compliant/complicit press corps. Having received options at $4/share (so you can make a ton even if the stock does nothing), you don't care if the company makes money or not. It is all in the spin. Directors serve on boards of many companies, and they help each other out. It is all worse than a Ponzi scheme. And, all perfectly legal.


Edit: what makes matters worse is that the shares they are issued dilute the shares of real shareholders by increasing total shares. They are stealing from their owners, and hide the fact in the insane complexity of the accounting process, and in the fact that most owners have no idea how this process works and how it harms them.

I think banking is affecting timeframes also. The banks are demanding continuous, short term,improvements as a condition of further investment capital. There is a nice description of the situation in William Greider's "One World, Ready or Not".

But they do. Here is a Bakken blurb talking about the plan which obviously is going to take years and years to drill through. 6000 wells down, 48000 to go. Certainly no one is planning on doing that in the next quarter, but are indeed are instead making a multi year development plan argument.

Or as they say on Wall Street: they sell the sizzle...not the steak. The sizzle comes quarterly...the steak (and thouands of new wells) takes years. I wouldn't put it all on the CEO's though. Folks who want long term/modest returns buy the blue chips like ExxonMobil. And then there are those who demand a 30% return in a year or two. I've seen more than one CEO and board member run off by shareholders because they weren't delivering such gains.

Maybe I've been missing something, but even though its ostensibly too expensive to ship gas that is normally "flared", why is it not used on-site for power generation etc. via internal combustion or turbines?

Is there any room for 'gleaners' with compressors and propane trucks to haul some of the gas away before it is flared?

N - I use lease gas on many of my wells to run the process. Unfortunately it takes a relatively small volume...typically much less than the flare. I once ran economics on running small skid mounted NG fired generators to use for stranded NG. Though fairly automated the economics still didn't fly...and that was selling at retail prices directly into an aluminum smelter.

In the end it will always be about the economics. But if the regulators made flaring illegal much of that stranded NG would become economical: given the choice of transporting the NG or not prodcing the oil the effort would be worth it to the companies in many cases.

Why don't the re-inject the gas into the liquid plays? It seems that would help maintain pressure to push the liquids out. What am I missing?


Works pretty well in Prudhoe. Not so much in poor permeability rock dominated by fractures.

jj - As Bruce points out not all reservoirs respond positively to NG injection. In fact, in some cases it can damage productivity of off set wells. And there is still the economic issue. in general injection wells cost more to drill than producers. It also requires the same dril rig: while a company is drilling an injection well it's not driling a revenue producing well.

The bottom line remains: if the regulators don't mandate capture of flared NG then short term economics will rule the process


Looks like some people are working on the problem, with small GTL plants.

Wonder if it would fit on an offshore platform? Probably not.

Regulation is what is required, I am currently working in Russia, due to a higher GOR than expected, we have more gas produced with max oil production than we can fit down the gas line. Therefore we flare until we hit the government allowed limit then we cut oil production. We have since gone back and re-perfed to lower the GOR.

When I first started in the North Sea the amount of flaring amazed me, I was told the gas was flared not because it was uneconomical to produce and sell, but a dollar invested in gas sales would have X valve where, investment in oil sales would return 10X, so all investment was put into oil with gas treated as a waste product, but it amazing how a government can refocuses a companies priorities.

It makes me laugh at some of the areas targeted for there CO2 emissions when standing at the hand rail while flaring millions of cuft gas a minute. At least the Russians are on the right track at least where a western company has to pick up the bill, lets hope they bring in the same regulations for the Russian companies as well.

Just for the record most if not all offshore production platforms burn gas for main power use with diesel backup, can't speak for land rigs.

This start up company is defiantly trying to take care of the flare gas market, and good luck to them. GTL plants to fit on FPSOs and the like. Some good graphs outlining the options for flare gas depending on volume and distance from market.

Seems to defy logic. Shell, at least, thinks that GTL works because of the economics of scale:

Pearl GTL formal inauguration today

The integrated gas-to-liquids project, being developed by Qatar and Shell under a development and production sharing agreement (DPSA), will produce 140,000 barrels of products each day. The state-of-the-art plant will also produce 120,000 barrels of oil equivalent per day of natural gas liquids and ethane.

Shell invested $19 billion in this one.

Sasol seems to agree with you, in that size is important.

But there are other companies working on flare gas to GTL with small plants. They seem to be relying on modular / production line construction to lower construction costs, but they still seem to quote low operating cost. We may have to see what happens once some of these ideas get into production. Then again if oil stays above $100/bbl, then that price is all they need with free to negative priced gas.

I will be happy to see any method of reducing flare gas, as it seems such a waste and abuse of infinite resources to me and I am no greenie, but I can't stand waste.

I believe this is the best link but many more below

Exactly banned. Shell can justify $19 billion for that project but not $1 million each for hundreds of smaller projects. As I think you imply it all boils down to cost per unit produced. Produce enough units to amortize the initial capex profitably and you're good to go.

Here's a link to a 11/10/11 presentation on new restrictions by the North Dakota state government on flaring, and reports on gathering processing and transportation capex plans for Bakken gas, as well as pilot projects to use gas to power wellsite equipment now running on diesel, run distributed generation to use the electirc grid to caputre the flared gas energy, or do distributed collection.

Good link.

I have long thought that on site electrical generation should be a viable option where there are no NG pipelines close by, as there are always electrical lines close by, if not at the site itself.

They key issue then is the selling price. What is needed to make it happen is a set price - a feed in tariff.

Once this is done, the companies, like Blaise Energy, can engineer standard skid mounted units accordingly. Since the fuel is "free" the generation efficiency is not a real concern, it is the return on investment that is key. This will influence the type of equipment used - longevity and low O&M over efficiency, and this can be seen in the types of engines that have been used in oilfields for decades - heavy, bombproof low rpm engines.

The high speed engines that Blaise is looking at will not last as long, though they are cheap, mass produced items.

In any case, a solution is out there. It just needs a fixed price for the electricity, and a very simple/minimal approval process, and it will start to happen.

of course, if the ND gov mandated "no flaring", then it would happen anyway, and the cost of setting up an electrical generating system is just a cost of doing business.

A final note - using the gas to power the rigs seems a bit much - part of the drilling is done before you have even reached gas. I think flaring while drilling is fine - it is only a temporary activity. But once a well is completed and put into production (and the gas flow is known) that is the time to use the gas.

Very small generators are not only substantially less efficient, they are more costly per unit of capacity and require higher maintenance per kwh. I guess I need to look at the well spacing and the flare rate, but it seems like the difference in capital cost and efficiency ought to drive bigger units and more low pressure collection (I'd be looking to use 2MW rather than 200kW units). I'd see the biggest obstacle as low ND power prices, though.

Use of gas on-site for diesel equipment may be more practical than we'd think, given that wells are being drilled quite close to existing wells, and that the drilling activity is causing diesel shortages.

The ND DNR is substantially restricting flaring: wells will have to restrict oil production or collect gas instead of flaring it within 60 days if production is above 200 bpd, within 120 days if production is above 150 bpd, and within 180 days if production is above 100bpd. Based on the info we've seen here, I'd say that would affect a majority of wells.

b - Truely frustrating. In my example the aluminum smelter had to occasionally shut down for lack of NG from the local utility. You can imagine they were willing to pay top $. But as you say the economics just didn't work: the initial capex was too high and the return was too low. And in that case it wasn't flared NG but reserves I would have to intentionally drill for so that added more capex to the mix.

I'd say that would affect a majority of wells.

No, it doesn't.

First, those restrictions are not universal across ND, they are applied to individual field (spacing) rules.

The function of the NDIC is to prevent waste and protect correlative rights.

In the past operators have gotten extentions of the time limits for flaring gas on an individual field basis because they convinced the NDIC that wasting gas will prevent waste. The NDIC may want the public to think they are doing something about gas flaring but, in effect, the operating companies make the rules.

If an operator testifies that flaring gas will prevent waste because the value of the gas is a small fraction of the value of the oil, the NDIC will conclude that wasting gas is preventing waste.

The NDIC's decision in these cases is based on the evidence and testimony they are presented with. If no one shows up to say: "Hey you dumb f**kers, wasting gas is not preventing waste", the NDIC will rule with the company claiming wasting gas is preventing waste.

The vast majority of wells can't sustain the level of production prescribed by the NDIC on an individual field basis.

Finally, if what you say is true, why is ND flaring 200 mmcfd and increasing. Here's more details on a gleaner operation to reduce flare rates. The operation this one company plans to set up next year will capture 1/3rd of the currently flared gas without requiring pipeline construction or compressor purchase by the producer.

The info in the bakken express link below seems to me to indicate that the technical and financial feasibility is there and there will soon be no reason to flare a hole beyond a few weeks unless it is far below typical production levels. Seems like NDIC should change the rules to be significantly more restrictive. Maybe, any producer flaring more than X% of produced gas shall not be allowed to bring any additional oil to production until flaring is reduced to that level, with the level ramping down from current levels to U.S. typical levels over a 2 year period?

The info in the bakken express link below seems to me to indicate that the technical and financial feasibility is there and there will soon be no reason to flare a hole beyond a few weeks unless it is far below typical production levels.

It seems to me to indicate that the technical and financial feasibility is already there. I challenge anyone to show how it can be more economical to flare gas on this one instead of installing a gas sales line with a few months delay. Go ahead pick your own (reasonable)numbers for time delay and pipeline costs.

zone date oil water gas prod. gas flared
BAKKEN Sep-11 10371 3390 29629 29629
BAKKEN Aug-11 10026 6821 23012 23012
BAKKEN Jul-11 8911 6068 13225 13225

Liquids rich gas such as this one recently sold for $7/mcf. I noticed your link to bakken express used $8/mcf.

b & b - I read the business plan. There's absolutely nothing new in their proposal. "...the technical and financial feasibility is there..." As far as I can tell the capability they're describing has been around for over 50 years. I used my first skid mounted NG compressor 32 years ago. You lease the compressor (paid for with cash flow from the NG sales) and fuel the compressor for free with some of the produced NG (as has been done for over half a century). It's pretty much a no-brainer. First, there has to be an existing NG sales line within economic distance...just like for any NG production. Second, all they're doing is offering themselves a NG compression contractor. I can call a half dozen companies this morning who'll install a NG compressor on any lease in the world.

Details guys, details: they start with the assumption that there's a nearby NG transport pipeline. And if there isn't? Then they just keep flaring the NG.

they start with the assumption that there's a nearby NG transport pipeline.

There are gas sales lines within a mile in three directions from the well I showed production for. Now make it 'economical' to flare the gas. Its not economical, it is comical.

I'm not close to being an oil guy (I grew up in AZ, or I'd know more from kibbutzing).
Transport by truck as CNG at 3000psi from the compressor isn't common, is it? The pilot project transported the CNG 30 miles and it looked economic to me to use trucks considerably farther.

How many 30 psi to 3000 psi, 700mcfd compressors can you lease tomorrow? Aren't most of the well skid compressors at lower outlet pressure?

b - There are two basic types of NG compressors that can be skid mounted...I'll skip the details. But you can install a combination of these compressors in serious and get whatever pressure you desire. Again, a lot of expensive horse power but you can do it anytime you want. I can hook up 30 frac trucks and get you 20,000 psi all day long. BTW that set of trucks would cost you $32 million.

Also, I'm not arguing their approach won't be economic...don't know the details. But it doesn't pass my initial "smell test". I could easily be wrong but I've seen similar pitches trying to collect individual investors into such a consortium and many only made a profit for "management". Management that seldom had money invested in the business.

My main point was that the methodology they're pitching has been around for decades. If the economics were there to make it work it could have been done by any of the Bakken operators anytime they wanted to do so.

The extent of African bush fires is amazing.

Slash and burn?


I'm thinking no wildfire fighting.

There is a lot of slash and burn going on around there due to rapidly increasing populations but it is interesting that it is mostly in a horizontal line.


Sand to the north, rain to the south?

Maybe, there was a story in one of the latest NGs about the population and tribal pressures in Africa, check it out.


Gas flaring is not only stupid as it is a waste of gas but we should also because the possible amount of wasted associated helium, which will become more scarce and expensive in future, as an impressive rigzone article shows:

I've never seen an analysis of ND bakken gas that included helium. That may be because helium is not typically tested for.

The Williston Basin would seem like a likely kitchen to cook up some helium. There is an area in the WB that contains a large volume of high pressure nitrogen in the permian. I wonder is the helium gas content has ever been measured ?

The high pressure nitrogen is mainly a nuisance and has resulted in blow-outs during drilling and completion operations.

Here is a larger version similar to the top image:

Lights data from Defense Meteorological Satellite Program DMSP 1994-1995

I want to shed a little light on the reasons why so much gas is wasted. The main obstacle to bringing it to the markets is the nature itself. Permafrost and endless swamps make laying of pipelines a very expensive endeavour. And you can't just build it and forget. The environment is harsh, you have to constantly monitor the condition of the pipe. Otherwise you end up with countless leaks. Everything you bury gets pushed up by the soil when it freezes. Of course, all this is solvable, but eats into profits, making associate gas uneconomic to deliver.

If you look at the map, you'll notice that the area is scarcely populated. That is because nobody wants to live there. And for a reason.

And if you want to have business in the area, you better equip yourself, like this guys:

Wood Mackenzie on shale gas break-even costs (link)
Wood Mackenzie Shale Gas Breakevens

aws - Very good catch. Mucho thanks.

Significant points from the link. BTW: Wood Mackenzie is one of those independent consulting companies that have access to all the actual that you won't always see in those flashy press releases.

"Who is making money? An analysis of the results from Q4 2009 through Q4 2010 of both shale gas operators and related service companies illustrates that the operating margin is increasingly being taken by the service companies at the expense of the operators. " That's wealth transfer mentioned before.

"Supply economics support this financial picture with the majority of shale gas plays failing to break even on a full-cycle basis at prevailing gas prices – the notable exceptions being the liquids-rich plays. This analysis is backed up by a review of current drilling activity, which shows an increase within the liquids-rich plays, e.g., Eagle Ford, at the expense of the dryer gas plays, e.g., Haynesville. The attraction of an additional, valuable, liquids revenue stream is rapidly driving up liquids-rich asset prices." And this is the pay off for the shareholders who are swapping their revenue stream to the service companies in exchange for higher stock prices. Works great...if you buy/sell at just the right times.

"It seems that the equity analyst community has played a key role in helping fuel the shale gas M&A market, acting as the chief cheerleader for shale gas plays. A review of historic analysts’ notes shows that their enthusiasm for reserve bookings and production growth has only recently been replaced with a focus on value, namely an analysis of which companies are actually making money, as opposed to recycling money." If that trend continues and broadens it could be very bad news for many of the shale players. But, IMHO, it will still be the Wall Street traders hyping those stocks that will rule the day regardless of what the analysts say. But when the day arrives that those two schools of thought come together, many of the shale plays could become graveyards for a lot of companies.

ROCKMAN - Thanks!

I have a question for you that stems from a comment you made the other day about the sands used in fracking to prop open the fissures created in the frack process. You pointed out that the forces were so strong that eventually the grains of sand would be crushed and that the industry was starting to use ceramic beads to keep the fissures propped open. My question, and it may be an obvious one, is what relationship does the ability of the sand to keep fissures propped open have on depletion rates.

On a further note, there has been reporting of low intensity earthquakes caused by fracking. It seems to me that the force of a small earthquake would serve to close up the fissures. Could fracking a new well raise the depletion rates of adjacent wells?

aws – Actually they’ve been using ceramic beads for decades. Fracture collapse is a well known phenomenon.

Yep…proppant crush reduces the permeability of the fractures due to closing. The crushed sand also reduces the perm of the sand matrix also. And that adds to the lower flow rate from the pressure drop as the reserves are produced. I’ve never worked such reservoirs in detail so I can’t offer a sense of how fast/to what degree this hurts the flow rate.

Offset production interference: that is THE question in such plays. IOW what is the effective well spacing? Too wide and you leaves reserves behind. Too close and you’re wasting money. And if that offset well has been depleted you could lose a $million worth of drilling equipment in the new well. And even when there’s a good model for fracture distribution Mother Earth can still break those rules anytime she likes. I’ve seen wells interfere with each at distances I would have never predict.

I can not believe that shale gas is not economic and will not have a huge economic impact for the simple reason that Exxon paid $30 billion for XTO Energy. Exxon is too well-managed and knows too much about what it is doing for them to make a mistake on an acquisition like this.

nd - The undeveloped shale gas leases that XTO had added little value to ExxonMobil. Mineral leases have a term period, typically 3 to 5 years, and if not drilled before they automaticly expire. XOM bought XTO's cash flow at a big discount. When NG prices crashed in '08 many SG players were unable to meet their debt obligations. I don't know exactly what XTO's balance sheet looked like but they did go deep into debt doing acquisitions.

After the SG crash I could have acquired the rights to drill on 100's of thousands of acres of leases for free. Companies had no choice: if the leases weren't drilled they would expire. Such a "farm out" would usually earn the original leasor a small residual interest in the new well. Regardless, 100's of $millions of leases expired without being drilled.

Well the operating income for XTO the last couple of years before the deal was $3B so it is a 10+ year payout if that remains steady. I note that Exxon said it was not laying off many of the XTO employees so it sounds like the plan is drill, baby, drill.

On expiring leases I have a pesonal connection. Chesapeak leased up some land we have in Houston County Texas from my dad and then let the lease expire