Tech Talk - the development of a natural gas market and the GGFRP

Recently the New York Times had a short series dealing with corporate and governmental e-mails on the natural gas found in shale in the United States, with some question as to the immediate value of those resources. I commented on the reports at the time, but it is perhaps timely as I review oil deposits in the United States to also comment a little on natural gas, since it is in part the availability of conventional natural gas, as well as imported liquefied natural gas (LNG) that together hold down the gas selling price, and in the United States, make it more difficult for the more expensive shale gas to find a profitable place in the market.

The power that can be released by burning natural gas has been known since 1777 when Alessandro Volta (he of the “volt”) used a glass “spark” pistol to ignite a mixture of marsh gas and air, and propel the sealing cork out some distance. By that time it had been several thousand years since the Chinese first piped gas through bamboo pipes to boil seawater. Following the more modern pathway, it was in 1792 that William Murdock (Murdoch ?) first used gas to light his cottage, though he “manufactured” it from coal, and it was initially this coal gas which was used to light homes, factories (1804), and in street lighting (London 1807).

When first used in 1816 in the United States, in Baltimore, the gas was produced from a gas works (where coal is heated and the resulting gas – mainly hydrogen and carbon monoxide – is collected, cooled, cleaned, and distributed). Much of the initial development of the industry (see for example, that of the Atlanta Gas Light Company) was built around generation of this coal gas. It was not until 1825 that the first commercial natural gas well was sunk in the United States, although an accidental well had been drilled (and caught fire) in 1815. That first well produced gas used for local lighting.

By August of 1825, two stores, (one a grocery store) two shops, and one mill (the property where the well was drilled) in the village of Fredonia were being lit by natural gas produced by the Hart well. The gas was brought to these buildings by use of small wooden pump-logs with tar-laden cloth over their joints for a distance of several rods. However, due to the permeability of these pipes, they were soon to be replaced by lead and tin piping. What impressed people the most was the lit gas did not emit an odor.

The first natural gas company in the United States was apparently the Fredonia Gas Light and Water Works Company of New York, founded in 1857, and renamed the Fredonia Natural Gas Co in 1858. For those who think that fracturing a well to improve fluid flow is a recent discovery, some of the earliest wells in Fredonia (December 1857) were artificially fractured to improve gas flow. The technique was, however, perhaps a little primitive:

"In Risley seed garden, adjoining the creek, a boring has been made by laborious drilling in the solid rock, four inches in diameter, and to the depth of 122 feet. No gas having made its appearance at this depth, the experiment was tried of blowing out the crevices of the rock with gunpowder. A canister of 8 pounds was accordingly sunk to the bottom of the boring, connected with the surface by a hollow tin tube. Through this a red hot iron was dropped, and the explosion which expelled the water in the shaft, was followed by a plentiful supply of gas."

Interestingly the price for the gas was $4 per thousand cubic feet (kcf), which meant that the local town paid $16 per year per street light which illuminated most street corners and businesses by June 1859.

The first commercial heating application mimicked that of the earlier Chinese application in that it was used by William Tomkins to evaporate salt brine in the Upper Kanawha Valley of West Virginia, in 1841. However the temperature produced was not that high, and it was not until 1860 that Robert Bunsen created the variable air/gas mixing burner familiar to those of us who used it in chemistry class. This ability to create a much higher temperature (which Bunsen needed for his work on spectroscopy) showed that natural gas could be an economic fuel. However, because it is used in greater relative volumes than the competing fuels coal and oil, and storage was not that simple, it was not until the growth of natural gas pipelines following World War II that the industry began to grow significantly; although, during the Gaslight Era, natural gas was, until the 20th Century, the dominant method of creating artificial light. But while this market was of some significance, it was largely a local industry and did not provide enough market to use the quantities of gas that were becoming available from other sources.

Because of the lack of methods of collection, distribution, and delivery to an adequate market, much of the early natural gas production that came about with the mining of coal or the extraction of oil was considered more of a nuisance than a financial benefit. Without an efficient pipeline network, the gas found in coal mines was diluted to safe levels and released to the atmosphere. In oil wells it was, and often still is, flared at the well head. For example, at a well in North Dakota this year.

Flaring gas at an oil well in North Dakota (Glenda Baker Embry)

In many countries gas flaring is still widely practiced as the predominant method of disposing of the natural gas that comes out of an oilwell with the oil. Because of this, in 2002, the World Bank started a Global Gas Flaring Reduction Partnership (GGFRP) to capture the value of the otherwise wasted resource. As an example of the scale of the wasted resource consider that in 2009 Indonesia flared 3.7 billion cubic meters (bcm) of gas (0.98 Tcf), worth about $450 million, but now plans to eliminate all but “necessary” flaring by 2025. Saudi Arabia flared 38 bcm in the 1980’s, but by 2004 had reduced this to 120 million cubic meters. The GGFRP estimates that some 150 bcm (5.3 Tcf ) was flared globally in 2006, 30 bcm (about 1 Tcf) in Russia alone. The World Bank hopes that, through the GGFRP much of this will, in future years, be captured and marketed.

This growth of supply requires largely only the provision of a network for collection and distribution, since the gas is produced as a byproduct from the oil that the wells were sunk to find. Thus, as this comes into the world market, it will provide additional volumes in the near future that will provide continued competition against that produced from the shales of the world, but at a lower price.

Similarly the costs for production of natural gas from the more permeable rocks of conventional reservoirs will remain below that produced from shales, and so I will continue this series for the next week or so by taking a look or two at conventional gas reserve development in the United States since the Second World War.

Thank you Heading Out for your technical series of posts. I find them to be highly informative and beneficial.

Since Natural Gas is, amongst other sources, one of the byproducts of producing oil, what happens to the gas production as the oil well depeletes? Does it tend to drop in tandem?

As for the gas market, when the well is finally closed-in due to being uneconomical, the gas production will also cease.

To answer your question about what happens to the gas is there are multiple approaches, but the preferred technique is to keep the gas in the reservoir for as long as possible. Because gas expands with reduced pressure as oil is taken from the reservoir it acts as the driver to push the oil to the surface. In a reservoir, because gas is less dense or lighter than oil, it floats on top of the reservoir. Oil wells are perforated (holes put in the casing where the oil comes out) well below the gas oil boundary to maximise the benefit of this effect. As the oil is progressively produced, the gas content increases and needs to be handled as Heading Out describes above. Eventually the remaining gas cap is "blown down" or produced once infrastructure is put in place. This is the state at much of Pruedoe Bay, in Alaska, where the produced gas is still pumped back into the formation, while waiting far the economics of building the pipeline south to improve.

There are many different kinds of reservoirs which complicate the above description, for instance the gas is in the oil and is only released when pressure decreases as the oil comes to the surface and must be dealt with then. This is the purview of reservoir and production engineers, but the general intent is to keep it in the reservoir for as long as possible.

Lurker – NG associated with oil production: there’s a very wide variety of circumstances. At one extreme many oil reservoirs have virtually no NG associated with them. At the other end are oil fields with very high concentrations. Additionally you can have segregated reservoirs with a free NG cap sitting on top of an oil layer. That oil layer may or may not be sitting on a layer of water. In such circumstances we typically only perforate the wells in the oil layer. Such wells usually produce a relatively small amount of NG with the oil. Once the oil production reaches an uneconomic level the wells can be recompleted in the “gas cap”. As far as changes in the GOR (gas/oil ratio) as an oil field is produced there’s a variety of dynamics that can develop. In pressure depletion reservoirs as the pressure drops more of the NG dissolved in the oil is liberated in the reservoir and is produced with the oil. At a certain point wells with a very high GOR are shut in to avoid lowering the pressure even more. Mexico’s Cantarell Field is a world class example of this phenomenon. The largest N2 production plant ever built has been pumping its product into this oil reservoir to enhance the URR. In addition to slowing the decrease in oil flow rate it minimizes the amount of NG brought out of solution. In extreme cases if enough NG comes out around a well bore a “gas block” can be generated and completely cut off the flow of oil to the perforations.

Pre-1970’s NG was seldom the primary exploration target. There was little demand since there was a very limited distribution system. Often if a significant volume of NG was associated with an oil reservoir it was flared to allow the oil recovery. In time as oil discoveries decreased and the distribution system expanded NG exploration took off. Today pure oil reservoirs are rare in the US. Even conventional NG reservoirs, especially large ones, are also limited. Thus the push for unconventional shale gas reservoirs. Not so much that they are very profitable but because there are not enough conventional targets (both oil and NG) left to support the number of companies in the oil patch today. Especially true for the public companies. If they can’t provide Wall Street with the sizzle of an ever increasing reserve base there’s very little reason to bid their stock price up.

The technique was, however, perhaps a little primitive

No gas having made its appearance at this depth, the experiment was tried of blowing out the crevices of the rock with gunpowder. A canister of 8 pounds was accordingly sunk to the bottom of the boring, connected with the surface by a hollow tin tube. Through this a red hot iron was dropped, and the explosion which expelled the water in the shaft, was followed by a plentiful supply of gas."

Fracking, back in the day, in the state that is about to ban the practice!

While there are some obvious safety issues here, I should point out that this "primitive" fracking method used no nasty chemicals, and created no liquid disposal problems, so it is, in reality, more environmentally friendly than the modern fracking methods.

It might be a bit more challenging to do this in a horizontal well, but I'm sure Rockman could find a way - an make sure no one is standing within a mile, or, two when it is set off!

Paul - Actually we have a much better system today which is identical to the black powder shot. Common name is "gas gun". The explosive charge is the same material used to fuel the Stinger missile. Relatively cheap and easy to deploy in a horizontal well bore. Unfortunately not nearly as effective as a hydraulic frac. Breaking the rock open has never been hard. It's not uncommon for it to be accidentally done while drilling. Just get the weight of the drilling mud too high and you’ll frac and rock.

The difficult part is keeping the induced fractures open. Frac the rock and the overburden pressure will force the fractures closed. To prevent this “propants” are pumped in with the fluid. Grains of sand or tiny ceramic pellets are pumped deep into the fractures and prevent them from closing. And that’s why they use those nasty chemicals. You can just as easily frac a rock with salt water as with those nasties. But just plain water won’t carry the propants into the fracs as effectively. Frac fluid chemistry is a complex field.

But again I’ll repeat the same point again and again: contamination of fresh water supplies directly by the frac’ng operation is very rare. I’m sure it has happened in Texas somewhere but in 36 years and observing hundreds of frac jobs I’ve never witnessed it firsthand. But there have been 100’s of incidents of pollution as a result of illegal surface dumping of many different nasties including frac fluids. That’s why disposing of such fluids in Texas is closely monitored. And heavily penalized when caught be it intentional or accidental. In Texas we inject those nasties into deep saltwater reservoirs. Apparently my Yankee cousins need to catch up to Texas standards. They are working on it: over the last few months both PA and NY have passed laws prohibiting PUBLIC MUNICIPAL waste treatment facilities from allowing frac fluids to be dumped (for a fee, of course) into their systems. Given all the public outcry and fear about frac fluids you would think the local administrators would have had second thoughts about dumping well advertised poisonous material into their watersheds. But I guess they never read their local newspapers.

Not that it couldn’t have happened, or might in the future, but I’ve yet to have seen one documented contamination problem during an actual frac job. But, based on the need for the new law, there must have been millions of gallons of those nasty frac fluids LEGALLY dumped into the watershed with the compliance of local treatment facility management. Frac’ng a well isn’t very dangerous. What’s dangerous is local authorities who knowingly allow hundreds of thousands of tons of poison dumped into their neighbors’ water supply systems.

Hi Rock,

I have seen a similar version of the "gas gun" used for doing avalanche control in the highway passes in the Cdn rockies - very effective, though, I am told, not as much fun as when they fire 105mm cannons at the mountains! Then again, in Stevens Pass, Wa, they use M60 tanks to do that job!

Having managed a municipal wastewater plant, I say shame on any operator that would let all those frac fluid nasties into their plant., and then the river, no matter how many $$ was paid to do so. The whole purpose of a WWTP is to separate bad stuff from the water, not put more in...

Wouldn't happen on my watch - or yours, I expect.

Paul - I've avoided pointing out the inconsistancy of fretting over frac'ng and the widespread accounts of the poor disposal methods used for all industrial wastes in the northeast. New Jersey has been the butt of countless jokes along those lines as long as I can remember. I suspect it was partly due to folks' frustration over higher fuel prices and the desire to "get the oil companies". And there's always going to be a fair level of political pandering.

As been pointed out endlessly frac'ng every shale gas well out there isn't going to have a significant effect on PO. But we are still trying to recover from a severe economic downturn that may, in fact, be on the verge of being repeated. With proper environmental safeguards my Yankee cousins could reap a significant economic windfall they need now. Developing the Marcellus et al isn't about PO IMHO. It's about adding economic stimulus those folks badly need. OTOH if they want to inhibit the process then so be it. Since they were to be the primary beneficiaries then they also get to be the losers. Their choice, as it should be IMHO.

Just saw an interesting report: apparently the NY gov agrees with me. He has not only lifted the ban of frac'ng in the state but has opened up 85% of the Marcellus play to driling. Of course with the caveat that there will be new regs for the proper disposal of frac fluids. Apparently one of the changes is the law passed just last week prohibiting municipal waste treatment centers from accepting frac fluids. I suppose they have to start somewhere. Prohibiting city officials from dumping poison into their neighbors drinking water source seems like a good place to start.

"contamination of fresh water supplies directly by the frac’ng operation is very rare."

yup repeating it over and over will make it so Rockman.

uh oh, not some kid making a movie this time...

black powder was nothing, after that they used nitroglycerin in "torpedoes".

pics of preparation of 600 quarts (568 liters) torpedo in 1973.

Many deaths and much destruction from nitro in the oil patch.

Not much to comment on, but thanks HO.

In your flare photo, there are power lines just a few feet away. Why can there be "micro gen" of flare-gas with a reverse-metered approach? Free fuel - efficiency would be less important than reliability - surely there is a solution?

I may have the opportunity to shift my career from telecom to energy -- nat gas industry specifically. I need a solid 10 years to get the kids up and out. Are we at the trough or the peak of the NG market now, in your view?

Paleo - Just saw your question and since no one else answered I'll give it a try. Peak market? Interesting...I take it you mean peak demand and not peak production. It seems obvious to me that the crash in NG prices was directly related to the drop in consumption with the recession. Especially commercial demand. Thus peak market = peak consumption = peak economic activity. Now there's the $64,000 question I hate to guess at. In the long term it seems safe to expect oil prices to stay high over all. OTOH that should increase demand for all alternative energy sources: coal, NG, solar, etc. But OTOOH higher prices will crimp the economy and hold back consumption and thus also demand. But only to some degree. Just like all markets some companes will be positioned to take advanatge of this instability and others won't be able to survive the dynamics. I have no idea how to make that distinction but I would tend to make sure I understand/make decisions based more on that analysis (of individual companies) than trying to predict the NG market in general.

Thanks, Rock. I was actually speaking more of the cyclic nature -- NG is for sure not as exuberant as it was a few years ago, but supplies seem to be holding up. The company I'm looking at get most of their revenue from gas well monitoring and control equipment - they sell "bullets" to anybody's "army". If a lot of wells are being drilled, they'll probably do OK. If the wells dry up, so will a lot of the revenue.

International opportunities are a bogey - might be a nice upside market, or might be a money pit. I suspect both; Australia might be great, China might suck as the locals copy and "partner", and the EU might break even in muddle of regulations and land rights issues.

If the bottom is likely to fall out of NG drilling, though, I'd shy away.

paleo - I would probably trust any company on the NG production side more than any other segment. And the shale gas plays are part of the reason. Right now most SG trends don't look very attractive to drill. But most existing SG wells are pressure depletion drive and could remain commercial for decades even at current low prices. There are low volume NG wells in KY that are still producing after 30 years. Not much rate but they still need to be metered and monitored. And if your company is developing more cost effective sytems they might even sell better. After lease operating expenses a company might only be netting a few hundred $'s a month on a NG well. But if he gives up on the well it might cost him $5,000-10,000 to plug it. I've seen operators loss $100/month for a while avoiding plugging while hoping someone might drill another well on his lease or NG prices to rise.

So bottom line: if you prospective company is a "bottom feeded" (n honorable name, actually) it might be a good long term home for you.

Why can there be "micro gen" of flare-gas with a reverse-metered approach? Free fuel - efficiency would be less important than reliability - surely there is a solution?

I have asked myself this question several times over the years.
The answer used to be, that the utility would not allow net metering, so that was that.

Now that they do, there are options, but few seem to be getting implemented.
Seems to me the best way would be an old style oilfield engine, like this, running a generator. These engines are not as efficient as modern ones, but they will run for decades, and can use dirty gas as fuel no problem.

Some people tried using microturbines, but I don;t think they worked that well (and are expensive).

I think the biggest problem is that most oilfield operators aren't in, and don;t want to be in, the electricity business. That suggests an opportunity for a third party service company to do this sort of thing - maybe Rockman would know if any are doing this?