Shale, gas, and water

This is a short technical note as part of a series of tech talks that discusses some of the aspects of fossil fuel production. By the nature of the length of post that I think will hold people's interest, and what I think folk know and want to know, these posts tend to be very simplistic reviews of topics that are often, in detail, much more complex. I am very grateful to those who, in comments, help to illustrate that complexity.

One of the most promising sources of natural gas that has recently started to come into production is that from the shale deposits around the United States. Since it is possible that similar gas or oil-bearing shales occur around the world this provides a new potential source of energy that has some considerable promise, in the short term, for helping to fuel the world.

Shale, as a descriptive term, does not describe just a single rock, however, and there are a large variety of shale types. Consider, if you will, that much of the shale that contains the hydrocarbon started out as the mud at the bottom of a bay, as the algae bloomed, grew, multiplied and died, to be trapped within the mud and gradually buried with it. As the layer was further buried beneath additional layers of material, so the pressure, and increasing heat, gradually turned the oil in the algae into either oil or natural gas. Along the way the mud itself was compressed, largely dewatered, and baked so that it turned into what we now call shale. When these reservoirs are now tapped, they can produce large initial flows of natural gas, for example, in the Haynesville, the Garfield 25 H-1 just started production at some 20 million cu.ft/day at 7,700 psi delivery pressure.

There are other shale types that are found in producing fossil fuels. In the same way that the mud underlay the water where algae grew, it also pervaded the swamps where, during the Carboniferous era, the trees and vegetation grew that, in time, and to a degree under the same type of burial, pressurization and heating, led to the formation of coal seams. The mud underneath that was the soil in which the trees had been growing was also changed, and so it also formed the shale layer that remained under the coal through the eons. (In the North of England we sometimes referred to it as the “seat earth.”)

But while the term shale is used to describe a generic type of rock not all shales are the same, in the same way as not all soils are the same. By geological description the key part of the description lies in the bedded nature of the rock, and its high clay content. But is it the clay part of the content that I want to focus on in this piece.

Geologists are strict with their rules on sedimentary rocks. Sediment is divided by particle size into gravel, sand, silt and clay. Claystone must have at least twice as much clay as silt and no more than 10 percent sand. It can have more sand, up to 50 percent, but that is called a sandy claystone. (See all this in the Sand/Silt/Clay ternary diagram.) What makes a claystone shale is the presence of fissility—it splits in more or less thin layers whereas claystone is massive.

Shale can be fairly hard if it has a silica cement, making it closer to chert, but usually it is soft and easily weathers back into clay. Shale may be hard to find except in roadcuts, unless a harder stone on top of it protects it from erosion.

The reason for stressing the point is that of weatherability, or how the shale holds up in the presence of water. Let me tell a small anecdotal story.

Back some years ago we used to test rock for different companies, and had been sent some samples of a shale, which we were asked to saturate in water before testing. Due to some confusion we did not get that message initially, and the rock sat – as received – over the weekend. First thing Monday we got a frantic call, don’t put the samples in water. Turned out that two different sets of samples had been sent, and the other sample had been immersed in water over the weekend, and when the lab had looked in the bucket that morning, they had found a residual pile of particles as the shale had totally disintegrated in the presence of water. The shale was so sensitive that we ended up doing all the sample prep (cutting, coring, grinding etc) dry to make sure that we could keep the samples intact.

Testing different shale samples for their susceptibility to water attack, their durability if you will, is not that easy. One of the more common tests is known as slake durability, for which there is a standard test protocol. (Free version here. The sensitivity is also perhaps illustrated by the categories into which the results from another one of these tests (the jar slake test) can fall;

Different responses to shale testing in the jar slake test.

The durability tests generally involve the tumbling of ten intact sample pieces of shale in water for ten minutes, oven drying it, and repeating the tumbling and drying. The amount of material retained on a screen afterwards as a percentage defines the durability. But bear in mind that the shale may still have fragmented or softened.

I am putting a little bit of emphasis on how sensitive the shales are, in general, to water, because, when the oil and gas shale reservoirs are developed, the drilling is usually performed with a water-based mud, and the resulting fractures that are driven into the shale to provide pathways for the gas to leave, are created using a water-based frac’ing fluid.

Now there are ways of stopping, at least temporarily, the wetting action of the water on the shale. One way of doing this is by adding more polymers to the water. Particularly at higher concentrations these (which also make the water "slick") can reduce wettability and stop the softening of the shale, but some of that work is still part science and part art. And part of the question is how the shale will behave in the longer term after it has been wetted.

Remember that to get the gas out the fractures through the rock have to be held open, and the way that this is done is to push small particles (called proppant, but similar to sand in nature) into the fracture to hold it open and still give a passage way through the fracture for the gas to get out.

But if the wetted shale along the edges of the fractures does soften with time, then under the pressures of the well, it may deform around the sand particles that are holding the fractures open, and slowly close the fracture, reducing production rate over that anticipated from a fully open fracture, and reducing the potential overall recovery of gas from the well. In that case, in order to sustain production from the well, it will need to be refrac’ed, perhaps more than once.

Just a question H.O.

while we are talking about "BLACK" rocks. What is the difference between "Shale" and "Slate"?

The short answer is time, heat and pressure. Rocks are basically divided into three types: sedimentary rocks, which are formed from the sand, carbonates and mud sediments which are deposited and then consolidated - and shale is one of these. Then there are the igneous rocks, which come from intrusions of the magma flowing up through the earth, and these are rocks such as granite and basalt; then there are the third group which are called metamorphic rocks. These were originally sedimentary or igneous rock which has been subject to much higher pressures and temperatures so that the structure of the rock has been further changed (even the grains in the rock have been deformed). Slate is one of these and started out as a shale, before being transformed. Marble is another, being the altered form of limestone.

How much water does UNG consume, anyway? Can't find any numbers, just "a lot" or "enormous amounts."

Am reading Heinberg's coal book; Chinese are shooting for 286 kb/d of CTL by 2020 - using 2.5 mb/d of water in the process! Talk about a dead end, they don't get much deader than that.

KLR --If you're asking about all the hype regarding the amount of water used to frac the Marcellus wells in NY: it's a relative matter. I'll answer it this way - Thousands of times more water is used to flush the toilets in NYC on an average day then they probably used in the last 12 months in all the frac jobs in the state. That isn't to say those fracs might not have caused other environmental problems but the water consumption complaint in the Mother of All Red Herrings IMHO.

As far as CTL I have no idea but there are some TODers that seem to know a lot.


That comparison is interesting, but I am curious what the numbers are. How much water is used on average to create how much gas? I know that not every play is similar, but is an average possible? I ask because I hear the water argument a lot, but no hard numbers.

I happen to live (right) next to an injection site where every five minutes tanker trucks drive by to inject frac waste water from the Barnett into the ground. While the constant dust on our gravel road is annoying, and it SEEMS like the trucks are constant, when one really steps back and thinks about it, those trucks aren't really carrying that much water compared to what we must dump onto Dallas/Fort Worth lawns every day. Still, hard facts would be nice.

Andrew - subject to the frac size it's n the order of hundredsof thousands of gallons. Sometimes a good bit more. OTOH disposal wells would worry me a whole lot more the water conservation. These site tend to beowned by small companies with very shallow pockets. Almost all the worst ground water contamination problems I've seen first hand came from disposal operations. Watch those folks like a hawk and never believe a word they ever say. A little harsh I know but better safe then no more potable well water.

Yes, a bit scary, as we are on well water. Though I try not to drink it, we do have 120 head of cattle here and I am sure they would prefer not to be water poisoned. But the world does what it has to.

My understanding is that the injection here is pretty deep. Is contamination usually from not drilling deep enough? If so, would it be easy to prevent if all injection sites had to be third party/government inspected prior to injection? Once it was confirmed deep, wouldn't it be safe?

Good news: they don't allow injecting into the fresh water zones. Bad news: the stuff they inject is often corrosive and can eat holes in the casing across the fresh water zones and lead to contamination. All you can do is periodicly have the water tested...including salinity. Something odd shows up file a complaint with the water board and, subject to what they think, the injection operator may be forced to test his well for leaks.

A good reference I found while looking around is:
Marcellus Shale Environmental Issues (a PDF).
Has a good discussion of the geology, drilling costs, fracturing (and re-fracturing),
naturally occurring radioactive materials, produced water, etc.

From a previous tech talk: Making holes and cracks around oil and gas wells

In total, in the example given, some 450,000 lb of proppant was used to make the fracture, together with some 578,000 gallons of water.

But, the pdf referenced above quotes 3.5 million gallons for slickwater fractures in horizontal wells in Barnett shales. (vertical wells use less water)

From the NYC water dept page Drought and Water Consumption (scroll down)
a little over 1 Billion gals/day.

From an abstract on from a newspaper Binghamton PressConnects (paraphrased):
"... concern over water for 1500 gas wells in the Marcellus ..."
(can't get to the original article). So I'll assume 1500 wells/year.

So, 578,000 gals x 1500 wells = 867 Million gals.
So, order of magnitude a single days worth of NYC water.
3.5 Million gals x 1500 wells = 5.25 Billion gals - a weeks worth of NYC water.

Even if one doubles or triples the water use (for flushing mud, etc.),
it doesn't seem like that much, though I can't find figures for the local communities' water supplies - which might be more constrained.

But - the watery fly in the ointment seems to be local water well contamination,
AND what to do with all the waste-water from the well drilling and production activity,
and spills of chemicals during transportation. All of these have already occurred,
and Cabot Oil & Gas is being sued for water well contamination.
Cabot slapped with contamination suit

Another page with Marcellus info:

But - the watery fly in the ointment seems to be local water well contamination,
AND what to do with all the waste-water from the well drilling and production activity,
and spills of chemicals during transportation. All of these have already occurred

But I really doubt enviornmental issues would get in the way of drilling (that's not to sat they aren't important, of course) if we needed the gas. There have been lots of oil spills too. And coal waste. Meltdowns. Etc.

the water consumption complaint in(is) the Mother of All Red Herrings IMHO.

I must agree. Those who worry about water don't seem to realize that there are areas that have large surpluses. The water argument is often thrown up against ethanol too.

I once read that the water consumed by Minnesota ethanol plants was less than that used by the city of Minneapolis. Yet no one complains about the city's water usage which is taken from the Mississippi. And Minnesota's 10,000 lakes are ignored. No doubt the same thing is going on with shale gas.

Unlike oil water is a renewable resource. When it is "used" it does not deplete never to be seen again like oil. The oceans are full of the stuff and most of the earth is covered with it. Weather currents disperse it.

We are currently fighting water in the basement at the home place. We had about 9 inches of rain in October and the ground is saturated. The problem in many ethanol producing areas is a surplus of ground water which requires tiling to drain away.

A nearby relative drilled a new well a few years ago. The water was so close the the surface that it came up to within a foot of the top of the well. The water flows out of her basement faucets even when the pump is turned off.

People who choose to live in water short areas like Las Vegas and Southern California should do the conserving and stop trying to make every one else who has plenty of water conserve. If they do not want to conserve, move to a water surplus area. There are plenty of them.

Water usage is truly a Red Herring argument against both shale gas and ethanol.

Apparently you've not heard of the Ogallala Aquifer and it's problems.

Unlike oil water is a renewable resource. When it is "used" it does not deplete never to be seen again like oil. The oceans are full of the stuff and most of the earth is covered with it. Weather currents disperse it.

Water is a renewable resource, but overpumping can damage aquifers. It is my understanding that they can recede/collapse when the water is taken out and that space is lost (for our purposes) for good.

The oceans are full of salt water. Not that ocean water can't be desalinated, but that does take energy.

That's not to say that we couldn't solve the problem by conserving and diverting wasted water to important tasks. Water tax, anyone? You wouldn't believe all the palm trees planted in the desert.

If we were talking about well regulated operations that may well be true. But, we're not.

From what I've learned about Marcellus Shale operations in PA/WV area, I'm not yet convinced. (We lost a watershed--google "Dunkard Creek is dead" if you're curious--and while frac'ing may not be the primary culprit, it doesn't come out looking very good).

My concern is that clean water is being pulled out of fresh water sources and dirty water dumped back in. We're upsetting natural water cycles and adding who-knows-what chemicals (the frac fluid mixes are proprietary and undisclosed) back into the water sources. If they agree to accept it, municipal water treatment facilities are overwhelmed by the increased volume and, from what I can tell, there are no plans for building new treatment facilities to handle these water treatment needs.

The problem (in this case) is not frac'ing itself, it is where the clean water is coming from and where the dirty water s going to.

I would argue the comparison to NYC water usage is a red herring... we're not talking about adding more residential users to an established water treatment regime. At least in my area, we're talking about a new kind of water treatment need (frac fluids) stressing poorly monitored water sources.

Question about the shale gas plays.

How wet is the gas ? I.e how much NGLS are found normally in shale ?

It not something I've seen. If they are generally dry plays then they are not replacing the often substantial amounts of NGL's from traditional plays.

You're correct memmel. In fact any liquids, NGL, oil or water, would be a strong negative in most SG plays. The permeability of any rock is relative to the character of the fluid passing through it. The same rock can be much less permeable to any liquid compared to any gas.

Thanks ROCKMAN...

I'm starting the chew on the NGL bone see what I can understand.

I'd argue just from this that Shale is not even close to a replacement for traditional NG plays because of the NGL angle. I'm on record as not being a big fan of Shale and I think my basic concerns they are simply financial ponzi schemes for the most part are becoming clear as credit continues to contract.

Thats not to say they won't be a source of NG for high value products like fertilizer and plastics but as and general cheap energy source I have serious doubts.

I'll be watching our storage levels for NG with extreme interest over the coming year as we should begin to see what the real decline rate is from the drilling pullback.

However given that NG prices have not collapsed despite the glut I'm forced to add NG storage levels to my long list of numbers that I'm really skeptical about.

Lowly propane has become the last number that I have some faith in from the EIA.

It suggests that conventional NG production may well be declining rapidly ( thus my question about NGLS).

Sorry for going a bit off topic just trying to collect info...

I have a follow-up question on this.

When driving accross the shale fields in Utah between Green River and Grand Junction on I-70, one can see many drilling operations in progress at the moment, and I have always assumed this is for natural gas. However, many of the wells are subsequently equipped with small lifter pumps and oil storage tanks.

Are they producing oil out of the shale? or is this NGL? Is it of commercial interest?

Francois -- Don't know much about Utah geology but pulled some maps on line. Difficlt to tell. Looked like most of the oil production was a good bit north of yout travel line. I wonder if it may have been coal bed methane. Were the drill rigs smallish? CBM also tends to produce a lot of water especially at first. Typically requires pumping and storage tanks.

Shales would be a very poor choice for prducing oil or NGL. NG is usually the target.

You may be right - I have assumed the storage tanks are for oil, but it could be for water. However, the pumps are of the "pump jack" type, which requires a down-well piston. Maybe someone else can comment

They use pump jacks to move water too.

Under the Garfield 25 H-1 link above is:

Cubic Energy, Inc. announces a twenty-four hour peak rate from its non-operated Garland 25 H-1 well at 20,200 Mcfe/day, on a 24/64 inch choke, with 7,700 pounds of flowing pressure, producing from the Haynesville Shale formation.

Searching on gas well testing procedures yields the Motely Fool post The Well Test Wall of Shame

The problem is that there seems to be no reporting standard whatsoever when it comes to initial production rates. Some companies quantify this production period (24 hours, 30 days, and so on) while others don't bother. Some report the results of a production test, which implies the use of test equipment that may or may not match real-world production conditions, while others report the average volumes actually flowing through surface equipment to sales.

. . .

In other words, these Haynesville well tests make for big headlines, but the EURs aren't tracking the IP number nearly as closely as many investors are used to seeing. Haynesville players such as Goodrich and Petrohawk Energy tend to shout their often vague initial production rates from the rooftops, but I worry that these announcements don't serve investors particularly well, especially at this very early stage of development. It's far from clear today what the "average" Haynesville well will look like over the course of its productive life. Variability is actually running quite high.

But judging from the press headlines, many believe that these shales push the scarcity problem off for decades. As evidence, being screened at Copenhagen is Haynesville: A Nation’s Hunt for Energy. Paraphrasing a quote from the trailer: "(This) resource alone will drive or power our country for several decades."

IMO, a piece on gas shale testing and prediction would be useful.

JM - Maybe HO has something planned..he's such a productive sort.

But here's a very short and simple answer: the initial flow rate of any well, regardless of how it's tested or documented, offers no certain indication of it's ult recovery. Absolutely zero value.

I've seen wells test 500 bopd initially and yet cum only 20,000 bo. I've seen wells come on at 50 bopd and cum 500,000 bo. The ult production of any well is a function of how much reservoir rock it drains. How much oil/NG it can test is a function of it permeability. Using initial test rates can be even more misleading in the SG plays then conventional reservoirs. But there are extensive testing proceedures that can offer much info on the future of a SG well. And I've never seen one operator ever release such data to the public.

Hi Rockman,
Here is a completion report on a Haynesville well in the Shreveport, La.
COMPANY: EXCO Production Co. LP, Hewitt Land Investments LLC 33, 1: 239572. LOCATION: Caspiana, S 33, T. 14N R. 12W. DAILY PRODUCTION: 18220 mcf gas on 22/64 choke; 0 barrels n/a gravity condensate; 620 barrels water. PRESSURE: 7019 lbs. SPECIFICS: Haynesville non-unitized; perforations, 12601-16781 feet, depth, 16886 feet.

Here's my observation and question: I have noticed on almost all of these shale wells in the Haynesville there is a tremendous amount of water produced; I am supposing that this is probably frac water flowing back. From my years as an operator of conventional wells I would think these wells would produce a whole lot more gas once they clean up. It is mind boggling to think of forcing 18MMcf of gas and 26,000 gallons of water through a 22/64" in hole in 24 hours! If the water wasn't there a whole lot more gas would be produced.(with a higher flowing pressure) It this were a conventional well and making that much water I would have to think the water cut would only go up from there. Does this water cut increase or decrease?
thanks, bob

You're probably right boby...frac water. But that's the problem with non-standard reporting: you never know where you are in the process. Not posstive about water cut changes but I suspect that once a stable flow is established the w/c doesn't change much. But there's always exceptions.

In my experience, produced water = high disposal costs and an early well death. If those cuts continue I would anticipate production to drop off early. I just never hear any comments concerning what I view to be a BIG potential problem.

boby -- As you might suspect long term water production would get to be a terminal problem as the pressure dropped verl low very quickly. One thing to pump a high w/c stripper oil well. Another to "pump" a high w/c NG stripper well. Time to just pump that plug and move on with your life.

FWIW, the Haynesville documentary website

Thanks for the link.

Interesting - the synopsis says "170 trillion cubic feet or the equivalent of 28 billion barrels of oil", but a review (Eye for Film) says "...enough energy to run all of America’s energy needs for nine years without help from any other source."

I don't think so: off top of head: 20 Million barrels/day x 365 = 7.3 Billion/year, and oil roughly 1/3rd energy supply.

per the EIA (2008) US total energy use for that year.

petroleum 37.1 quads
gas 23.8 quads
coal 22.5 quads
renewables 7.3 quads
nuclear 8.5 quads
  TOTAL 99.2 quads

oil is 37.1/99.2 = 37%.
7.3 Gbo / .37 = 19.7 Gboe/year US 2008, so 28 / 19.7 = it's only 1.4 years.
Such mis-information is as bad as climate change denier lies.

Did they mess up the rest of the numbers?
170,000 cubic feet = 174,760,000 BTUs (EIA energy calculator won't go to 170 trillion!)
times a billion -> 175 x 10^15 BTUs (aka quads), 175/99.2 = 1.76 years. (kinda close to 1.4???)
175 quads / 5,800,000 BTUs = 30 Billion boe.
? 170 quads / 5,800,000 BTUs = 29 Gboe. ???

1 barrel of oil = 5,800,000 BTUs (per EIA), x 7.3 billion = 42 quads.
37.1 quads / 5,800,000 BTUs/bbl = 6.4 billion bbls.
What gives? in-exact conversion factors?
NO wonder, the Wiki says that it's just an IRS definition.

EIA says 7.136 Billion bbls oil & products in 2008.

Interesting post. I'd like to get my hands on some oil shale to runs some gasification tests. Ever hear any news about oil shale gasification?


That estimate of volume of water and pounds of propent is for one frac stage. Horizontal wells normally have multiple frac stages. Operators could frac every 300-1000 feet. If the lateral length of a wells is 3000 ft, it may have up to 10 frac stages. So about 5 million gallons of water could be used in this example. Depending on the formation anywhere from 50-75% of that water is recovered. Most of the time the water is treated and used in another frac job. In my opinion the amount of water used should not be much of an issue. Cases of water contamination are isolated incidents. There are already strict regulations for the transportation and disposal of waste fluids. If you think about how much oil/gas/water the energy industry moves around; im sure you'd be surprised there arent more incidents.

Just about all of that initial water production is frac water. Water saturation is pretty low in shales. In the Barnett the wells will always produce some water, bc the well probably got fraced into the aquifer underneath. I forget the aquifer's name but it is not one that people drink or use (its 6000+ ft deep). Other shale plays like the Fayetteville eventually stops producing water.

I hear people talk about how 170 Tcf will last us decades or something. Look here ( 25 Tcf per year! I had no idea the US uses so much NG.