The Pearsall shale is a Cretaceous age rock formation (65-145 million years old), known to be productive  primarily of dry natural gas.  In South Texas, as part of the Rio Grande embayment, it is located  several thousand feet deeper than the Eagle Ford shale. In the Maverick basin, the Pearsall Formation defines a regionally occurring shoal-water limestone complex, and open-water shelf system with a maximum thickness of 500-600 feet.

There are Pearsall shale gas wells dating back to the 1960′s, however horizontal drilling and hydraulic fracturing technologies developed in the past decade have made this deep formation more attractive to oil and gas exploration companies.   So far, Encana, Anadarko and Newfield Exploration have recently drilled exploratory Pearsall shale wells in the Maverick Basin, and several are now producing dry gas. (These wells are in Dimmit, Maverick and Zavala counties.)  South and Eastward, where the Pearsall shale lies at an even greater depth, there has been little interest in wide scale drilling programs so far.

In the Cretaceous age geologic column of South Texas seen below, the Pearsall shale lies beneath the Glen Rose formation, or the Suart City Reef Trend, depending on where it is located in South Texas.

Why The Sleeping Giant, The Pearsall Shale, Is Still On The Back Burner

Lack of interest in the Pearsall shale is primarily due to the fact that natural gas prices are depressed, and greater riches lie in the liquids – rich Eagle Ford shale, which is located thousands of of feet above the Pearsall shale. Pearsall shale wells are typically more expensive and more difficult to drill than Eagle Ford shale wells, due to their great depth and the potential for encountering depleted zones such as the Edwards.   A report in Oil and Gas Journal in 2009 hinted that the Pearsall shale could be the “next Barnett Shale”. It could very well be,  someday, but not with today’s low natural gas prices.   As of  Jan, 23, 2012, natural gas was selling at $2.45 per million BTU. This price for  natural gas is about $10 per MM/Btu cheaper that it was  in 2006. See the natural gas price – history chart below.

Historic Natural Gas Prices. $ per MM/Btu

The fact is, natural gas is now  seen as almost a “waste or by – product”, produced in great quantities from liquids rich wells in the Eagle Ford shale and other areas. In the Eagle Ford shale, it’s  the liquids, such as oil and condensate, that  companies are after.  Natural gas must still be produced from these wells and either sold or flared .  Will such a valuable natural resource as natural gas continue to be worth almost nothing? Companies such as Chesapeake Energy are guessing that it will not.  Already,  dozens of U.S. and foreign power plants have been converted from coal to cleaner burning natural gas, and more new natural gas burning power plants are coming online each year. Few, if any new coal fired plants have been built in the U.S.,  due to both the low cost of natural gas and strict EPA regulations. Add to this a growing demand for LNG (liquified natural gas) on the world market, plus the conversion of thousands of cars and trucks each year to run on natural gas, and the future looks good for gas.

Here is an excerpt from a recent U.S. News article:  “Most of the people I know in the electric power industry are building natural gas” plants, said Jay Apt, a professor of technology at Carnegie Mellon University in Pittsburgh. That’s because of low prices over the last few years and the relatively low cost of building such plants, compared with coal-fired or nuclear.  Mr. Apt foresees higher natural gas prices as a result of this widespread conversion. “The surest route to $6 or $8 gas is for everybody to plan on $4 gas,” .

Chesapeake Energy for one, is  bullish on natural gas for these reasons, and because of  the fact that very few new gas wells are being drilled.  (Those wells that are being drilled  for natural gas are being done so only to hold leases that are about to expire.)

Here is what Chesapeake Energy had to say to shareholders in the 2010 annual report about the Pearsall shale in South Texas.  “This shale underlies most of our Eagle Ford acreage and is the second “sleeper” of our natural gas shale plays. We have two rigs dedicated to testing this formation, and our first few wells have significantly exceeded our expectations. This formation is found about 3,000–4,000 feet deeper than the Eagle Ford and so for the play to become competitive with our other natural gas shale plays, we will need natural gas prices to strengthen from where they are today. We believe this will likely occur in 2013 at the latest. We believe our 350,000 net acre Pearsall leasehold position could support the drilling of up to 3,000 additional net wells.”

This forecast from Chesapeake, made over a year ago, is probably a bit too optimistic in terms of when prices will rebound. Jack Barnes, global macro trends analyst for “Money Morning” forecasts that natural gas prices will remain low until the completion of LNG export facilities, expected to start coming online by 2015. These facilities will eventually export more than 17% of U.S. natural gas production.  Barnes predicts that in some fields we may even see natural gas selling for $0.00, or negative $ by this summer, after takeaway costs.

What To Expect Of The Pearsall Shale In The Coming Years

In the short term, perhaps for the next two to five years, natural gas prices will most likely remain too low to justify drilling new Pearsall shale wells.  In time, natural gas prices should eventually begin to rise, due to both domestic and international demand, and overall gas supply falling due to the  maturing of wells in the Marcellus, Haynesville and other shales. As the price of natural gas rises, drilling will most likely begin in earnest in the Pearsall shale. The timing for a Pearsall shale drilling boom (as well as  interest in deeper Eagle Ford shale dry gas), could very well coincide with a surplus of rigs, frac equipment, etc., as the Eagle Ford shale liquids play matures.  In the meantime, having a depth exclusion clause in your lease may just be a good idea. This will enable you to renegotiate a new lease for the Pearsall shale when it becomes more valuable.

Article by Nolan Hart, 01/23/2012

There are now several water companies actively seeking out landowners in the Eagle Ford shale area to make them lease offers for the water rights below their property. Many of these Eagle Ford shale water companies use the age old sales technique of getting farmers and ranchers to first see “dollar signs”, rather than thinking of the impact these large water wells may have on their neighbors and communities. In the Eagle Ford shale area there are several groundwater districts, including Evergreen Underground Water Conservation District and McMullen Groundwater Conservation District. These agencies have little power to regulate how much water is pulled from a well on private land.

The Carrizo – Wilcox aquifer is one of the most important sources of clean drinking water in South Texas, and one of the biggest sources of frac water used by oil and gas companies. Unlike more permeable aquifers such as the Edwards Aquifer (which supplies much of San Antonio’s water needs), water in the Carrizo does not flow quickly through the formation. It may take months or years for water to travel from the point at which it enters the recharge zone to a well.  Thus, it can be hard to prove that any given Carrizo Wilcox water well in the Eagle Ford shale focus area was “the one” that depleted water levels in neighboring wells. Water companies only need approximately four acres for one of these leases, and many new start up firms are actively advertising across South Texas that they are “Leasing Water Rights”.  The company agent will typically begin with talk of how much money the landowner can make, which can be thousands per month, and the fact that the landowner can use all the water they need from the “free well”.  What they do not typically spend much time explaining is how much water these huge wells can draw from the ground, and the fact that the lease is “held by production”, meaning you could be signing a lifetime water lease.

Things To Beware Of To Avoid Eagle Ford Shale Water Lease Scams

Beware of companies who focus only on how much money you could make, instead of on  the details of the contract they are offering. Have an attorney review any contract, and discuss the proposed well with a representative of your underground water conservation district. You may look up your local water conservation district here: List Of Groundwater Conservation Districts

Ask the company if they have done any studies to show what the impact of their well will be on the aquifer in your area, and if the company provides indemnification for damages to neighboring wells. Also, there should be some time limit on the contract, as well as a limit to how many acre-feet the company can extract from under your land. Do not give up all of your surface water rights either. Under some contracts, your stock ponds could be sucked dry, leaving your livestock without water.  Be very cautious of Eagle Ford shale frac water companies who claim to seek “non traditional” sources of water.  For example, if the company tells you they will only drill for “non potable, salty water”, and then use some kind of treatment to make it usable by oil companies, make darn sure that the contract that they offer you specifies exactly what underground zone that the “non potable water” will come from. Many contracts are so full of loopholes that they allow the  company to use any and all water on or above your property, regardless of what their sales pitch is.

As a landowner and member of your community, you should always consider the impact that a large commercial water well may have on your neighbor’s water wells, and also on the municipal water wells in your area. Do you really want to be the landowner who is perceived to be responsible for drying up your community’s well? While it a difficult thing to prove, your neighbors whose wells are drying up may cast a suspicious eye next door to your property, from which huge aluminum water lines originate and  transport well water up to twenty miles or more away.

Also, do not let representatives of these companies tell you that without their water well, oil and gas drilling will not come to your land. Under Texas law, oil companies can rightfully use a reasonable amount of water under your land to drill and complete oil and gas wells, on your property only. (When signing an oil and gas lease, make sure you do not give oil companies the rights to use the water on or underneath your land on any other adjoining properties.)

Again, never sign anything without first consulting with an attorney.

Article by guest writer Jeff Shaw, 1/13/2012.

In a recent conference call to investors on Nov, 2,  EOG chairman Mark Papa discussed ways that the company is using to reduce per – well costs in the Eagle Ford shale. Among the ways they are achieving this objective are  improvements in Eagle Ford shale well drilling and completion time, improved frac techniques and utilizing contract pumping services for frac jobs.

EOG’s Fastest Well Drilled In Eagle Ford Shale

The fastest Eagle Ford shale well drilled by EOG thus far is the Cusack Ranch #5H, which was drilled and cased to a depth of 15,467′ in only 13 days.

This appears to be a depth / time record that has yet to be  matched by any other operator in the Eagle Ford shale. One of the hallmarks of EOG Resources’ overall success in the industry is an “assembly line” approach to drilling and well completion. By following this “cookie cutter” type strategy they have achieved one of the lowest overall per – well costs in the Eagle Ford shale play.

Along with reduced well drilling time, improved frac techniques and service company savings, Mr. Papa expects EOG to shave another half million dollars in per – well costs in the coming months as they use self – sourced frac sand from their own mine.  No mention was made of where the frac sand mine is located, but the company recently began operations at a mine at Chippewa County, in  Central Wisconsin and is nearing the start-up of operations of a new frac sand processing plant in Chippewa Falls, WI. EOG is also in the process of developing its own frac sand mine in Cooke county, Texas.

Due to these cost cutting measures, the company expects to soon see Eagle Ford shale well costs at around $5.5 million.   EOG Resources reports that it is the Eagle Ford shale’s lowest cost oil producer.

Results Of Well Spacing Tests By EOG

EOG Resources’ original estimates of 900 million barrels of recoverable oil from their acreage in South Texas, (net after royalty) were based on a 130 acre well spacing plan. The company is experimenting with reduced well spacing, which could dramatically increase the amount of recoverable oil in their acreage in the Eagle Ford shale.  The company has closely monitored wells drilled with reduced spacing at the King Fehner Unit lease for more than 150 days, and reports favorable results. EOG is testing six additional multi – well plots of varying densities,  but is not yet ready to make a firm technical call regarding well spacing.

“Knife’s Edge Of Takeaway Capacity In The Eagle Ford”

In the conference call Mr. Papa stated that the company would continue to be on the “knife’s edge of takeaway capacity” until mid 2012 when the Enterprise expansion is completed. Meanwhile they are moving over 15,000 barrels a day by rail, most of which is capturing LLS pricing. (Light Sweet Louisiana which trades higher than WTI or West Texas Intermediate).   Overall, Eagle Ford shale oil is now trading at prices higher than WTI.

Due to the fact that wells can be drilled through more feet of  pay zone, and the fact that Sugarkane exists in the “sweet spot” of the Eagle Ford shale, (over-pressured, and containing large volumes of oil and natural gas liquids), it is proving to be a hot area of the overall play.  Aurora Oil and Gas Ltd, an Australian company, (With Marathon Oil as operator) will have drilled over 85 wells in the Sugarkane field by the end of 2011. Aurora  expects to ramp up their drilling program in 2012, running 10-12 rigs with 4 frac crews, and drilling 123 wells by year’s end. Aurora operates in 4 separate AMI’s or “areas of mutual interest” in the Sugarkane field, identified as Longhorn (28,280 gross acres), Sugarloaf (23,550 gross acres), Ipanema (4,600 gross acres) and Excelsior ((20,180 gross acres).

Players in the Sugarkane Eagle Ford shale play include Aurora Oil and Gas Ltd., Marathon Oil,  Pioneer Natural Resources, ConocoPhillips,  EOG Resources, Empyrean Energy, Eureka Energy, Geosouthern Energy, Murphy E&P, Petrohawk Energy among others.

The Sugarkane Eagle Ford shale trend runs roughly from Live Oak to Dewitt county.  Below is a map of the Sugarkane Eagle Ford shale play. (source: http://www.auroraoag.com.au)

The second illustration shows Aurora Oil and Gas’s completion procedure for wells in the Sugarkane field and how water aquifers are protected from contamination by frac fluids.

The new oil boom in South Texas is creating hundreds, if not thousands of new jobs. Among the hottest jobs in the Eagle Ford shale are truck driving positions. Despite this fact, trucking companies are finding it hard to recruit enough qualified drivers, for a number of reasons. At a recent meeting at Coastal Bend College in Beeville, several trucking firms voiced their concerns about the problems related to recruiting enough qualified applicants for Eagle Ford shale truck driving jobs.

Why Are Eagle Ford Shale Truck Driving Jobs So Hard To Fill?

Among the concerns that most of the trucking company owners had was the fact that one in four  applicants does not pass a mandatory  drug screening test. Another was that many applicants do not pass a basic background check. The applicant may not necessarily have a criminal record, but if they have too many driving violations they can’t be hired. Another issue that employers are facing is that  even if the applicants  have a valid CDL, they may lack the basic reading and math skills required to read company manuals, fill out load forms, calculate barrels of oil hauled, etc.

They also stated that there are more than likely many good candidates out there for truck driving jobs in the Eagle Ford shale, but that the majority of people who apply do so in person, and are not likely to apply online. If more job seekers were aware of how to fill out an online application, or were aware of the number of trucking jobs in South Texas and what they paid, perhaps a more diverse group of people might apply.  One trucking firm owner stated that they will “basically hire anyone with a CDL or commercial driver’s license who can pass a background check and drug screening”.

One would think that in these tough economic times the need to feed one’s family would be greater than the need to take recreational drugs, yet this does not seem to be the case in South Texas.

What Does It Take To Get A CDL In Texas?

1. You must pply in person at a Texas Driver License office.
2. You must present documents that verify your Identity. The requirements vary based on whether you are a U.S. citizen of lawful immigrant
3. Show proof of Social Security Number.
4. Meet the non-resident driver’s license requirements if you are not a Texas resident.
5. Have proof of Texas vehicle registration and liability insurance on all vehicles you own. (Or your employer must.)
6. Complete the application form.
7. You must be photographed, fingerprinted, and sign the application.
8. Pass the required vision exam. If you wear glasses, you must bring them to the appointment.
9. Pass the required written test for class of CDL you are applying for, including which endorsements your employer requires,  Pass A & B rules test (written), and the driving skill tests in the type of vehicle you will be driving.
10. Complete the HAZMAT or  Hazardous Material Endorsement Procedures.
11. Pay the required state fee.
12. You must provide a commercial motor vehicle for the driving exam, and present current liability insurance, Texas vehicle registration, and inspection for the vehicle. Note that if you are not licensed to operate the vehicle, you cannot drive it to the examination site. For more info you can view the state’s site here: Texas DPS

If you are in need of a job and would consider a move to South Texas to work in an Eagle Ford shale truck driving job, companies are literally begging you to apply.  Check sites such as Texasoilfieldjob.com and Coastal Bend Workforce Solutions for links to trucking company websites where you can fill out a job application. If you have a clean background record, (usually meaning fewer than 3 moving violations and no felonies), and can pass a drug test, chances are there is a truck driving job in the Eagle Ford shale waiting for you.  There is currently a need for frac sand truck drivers, vacuum truck drivers, gravel haulers, oil truck drivers and pipe and heavy equipment haulers.

Downsides?  Many frac sand hauling firms are looking for owner / operators, who have their own tractor, or trailer combo. These firms are offering sign on bonuses as high as $5,000. For those without their own rig, it may be a bit harder to find a frac sand hauling job. Those without rigs might consider vacuum truck jobs, or oil hauling jobs.

The Eagle Ford shale is now truly a multinational oil and gas play, with GAIL India Ltd entering into a joint venture with Carrizo Oil And Gas.  GAIL India is  that country’s largest natural gas distribution  company, operating pipeline networks, refineries, LNG terminals, along with an exploration and production division. GAIL, formerly known as Gas Authority Of India, was formed by the Indian government in 1984.

The Indian natural gas company GAIL will invest $300 million over three years. Most of the 20,200 acres involved in the joint venture will be in LaSalle county, Texas.  Gail India will have a 20% stake in the acreage.

Indian investment in the Eagle Ford shale comes on the heels of several other foreign based companies jumping into the lucrative oil and gas play in South Texas.

Below, Map of Carrizo Oil and Gas Eagle Ford Shale Activity.

Source: Carrizo Oil and Gas.

Some Of The Foreign Owned Companies Investing In The Eagle Ford Shale

China’s state oil company, CNOOC, has partnered with Chesapeake Energy. The deal which gives CNOOC a 33.3% stake in all of Chesapeake’s Eagle Ford shale acreage, cost the Chinese company over 1.2 billion dollars. Australian mining company BHP Billiton recently acquired Petrohawk Energy, a major Eagle Ford shale player, for $12.1 billion in cash.  Texon Petroleum, another Aussie firm is drilling in the Eagle Ford shale as well.

Statoil, an Norwegian company, has partnered in Eagle Ford shale with Talisman Energy and Enduring Resources LLC in over 67,000 acres in the Eagle Ford.

Korean National Oil company (KNOC) signed a $1.55 billion deal with Anadarko in March of 2011 which gave them a 1/3 interest in acreage in the Maverick Basin.

SM Energy recently announced a partnership with Mitsui, a Japanese company, giving them a 12.5% working interest in  SM Energy’s non operated Eagle Ford shale acreage.

Getting a true picture of how many years Eagle Ford shale wells will produce at this point is difficult. So far  it appears that as liquids production goes, those wells drilled in the “Goldilocks zone” or over – pressured, volatile oil window, which has reservoir drive, plus high carbonate content, will be the long term champs. We can look at Texas Railroad Commission production data from some of the first Eagle Ford shale wells drilled in the volatile oil window and get some idea of fall-off rates, but other factors come into play when looking at reported production figures. For example, many wells are put on a pumpjack when reservoir drive gas falls off, but the particular well you are investigating may not have been placed on a pumping unit yet, or is being choked back while the company waits on infrastructure, etc. Also,  R.R.C. production figures are  hard to interpret, since they are reported on the lease level. Unless there is just one well on that lease, it can be hard to determine how much  production is coming from the one well you’re investigating.  One Eagle Ford shale decline rate chart can be found here: Eagle Ford Well Decline Curve  It shows EOG Resources wells (mostly in the oil window) peaking at around 350 BOE/D, and flattening out pretty fast after eight months to less than 100 BOE/D. The term BOE/D means “barrels of oil equivalent per day, not “barrels of oil per day” and also includes natural gas and natural gas liquids. The term BOE/D is often used in investor reports rather than BOPD (barrels of oil per day), especially by those companies who have more acreage in the dry gas zone of the Eagle Ford. As a unit, one BOE is roughly equal to 6,000 cubic feet of natural gas.

How Much Oil Will Be Left In The Ground?

It has been estimated by some petroleum geologists that more than 75% of all the world’s oil is still left in the “mother rock” or source rocks, which happen to be shale. The rest of that oil migrated upward and was trapped in other porous rock formations where only a fraction has been recovered.  EOG Resources expects that the recovery factor for the Eagle Ford shale will be about 5%, compared to the Bakken Shale at 10%. Will oil and gas companies end up leaving in place 95% of the oil held in the Eagle Ford shale? The most likely answer is “no”,  and many  companies are already anticipating using secondary recovery methods, such as CO2 injection, to  force more oil out of declining Eagle Ford shale wells. In the technology industry there is a theory known as “Moore’s Law”, which states that the memory capacity of computer chips will double every two years. In the oil and gas industry, it has been found that with every doubling of wells in a shale play, productivity increases by up to 23%.  New frac techniques, secondary recovery methods, longer laterals and closer well spacing will most likely be used to increase the amount of oil recovered from the Eagle Ford shale far beyond 5%.

Killing Some Of The Golden Geese?

(Some) oil and gas companies could be playing a delicate game in the Eagle Ford shale. It’s one that’s been played many times before in the industry and one which has ruined a lot of wells. It’s called the “pull ‘em hard and make it look good on paper to the investors” game. Right now it appears that some companies are trying to lure investors their way with high initial production or IP rates from wells that probably should be held back. It’s been proven over and over that the harder you flow back a new shale well, the sooner it dies. High IP rates may be good for investor reports, but perhaps not that great for the landowner in the long run. If you flow a new shale well too hard by using too large of a choke at the well head, you can cause the proppant, (sand, resin beads, etc., which is pumped into the formation during a frac job to hold tiny fissures open)  to flow back to the surface along with oil and gas. With nothing to keep them open anymore, tiny fissures and cracks may then collapse, reducing the life of the well. As a landowner, you don’t have any choice in the matter as to how hard an oil company flows a new well on your land, so, “too bad” if they let it “burn out” early to boost numbers reported to investors. So, when looking at the life expectancy of Eagle Ford shale wells, it will be interesting to see how some of the very high IP wells pan out over the long term.

Eagle Ford Shale Well Life Span Long But Low Volume After First Few Years

Despite the relatively fast decline rates of some wells, it looks like Eagle Ford shale wells will be producing oil and gas for a long period of time, just at very low volume. Currently there are at least a dozen major pipeline projects underway, crisscrossing South Texas to transport Eagle Ford shale oil and gas to  market. Oil and gas companies simply don’t sign long term contracts and invest billions of dollars into such projects without a firm belief that an oilfield will be a long term producer. There is so much land to be drilled that even with sharp decline curves, there will be lots of oil flowing into these pipelines for years as the play is drilled out.

Well costs are coming down into the $5 million range, so payback for an oil company can come in just a few months, even with steep decline curves.  Landowners may continue to receive royalty checks from a single Eagle Ford shale well for decades, especially with secondary recovery methods coming into play in the future, but shouldn’t plan on getting  the really huge checks after the first year(s).

Article By Nolan Hart. Disclaimer: I hold no positions in any of the companies mentioned on this site.

Below are some photos of the new Baker Hughes office site near San Antonio as construction crews install drainage systems and prepare to begin building up the elevation of the land prior to the construction of office buildings. Ironically, the  new oilfield company site is located just across IH-37 from the new  Blue Wing solar project, which features rows of solar panels, generating energy for CPS.

New Baker Hughes complex south of San Antonio

Halliburton has purchased over 150 acres just south of the new Baker Hughes facility in southern Bexar County, near IH-37 and Loop 1604, not far from the location where Weatherford will also build a 17.5 million dollar operations facility.  Competitor Schlumberger has plans for a San Antonio area “supersite” in the coming months. As big as these developments are, it’s just the tip of the iceberg, as chemical companies, oil and gas companies such as EOG Resources,  and many others move in and begin to shape the city’s economic future. The arrival of all these oil and gas heavyweights means that San Antonio, which has struggled to find direction since the closure of so many military bases in recent years, is soon going to become an major oil and gas hub.

Article by Nolan Hart.

One of the biggest concerns that many South Texas residents have about the Eagle Ford shale oil and gas boom is the long term effect on water aquifers such as the Carrizo Wilcox. These water “sands” are not so much in danger from hydraulic fracturing, as some environmentalists would lead you to believe, but rather may suffer from depletion due to the amount of water used to frac new wells. How much that depletion amount ends up being is something that has bothered me for a while now.  Chesapeake Energy reports that a typical Eagle Ford shale well requires approximately 6 million gallons of water to drill and complete. With potential spacings as small as 80 acres to the well, and tens of thousands of wells to be drilled across the play, some fear a substantial drop in Carrizo Wilcox aquifer  levels. Another wild card that could come into play is that once all these new water wells are drilled, and oil and gas drilling is mostly over with, will ranchers sell their water rights and allow the wells to be connected up to pipelines, sending Carrizo Wilcox water to cities such as San Antonio?

All Doom And Gloom Or Just A Need To Proceed With Caution?

I’m beginning to come around and accept the fact that the Eagle Ford shale can be developed responsibly, with a minimal amount of impact on the Carrizo Wilcox. I’d still like to see more studies done, but here’s how it looks so far.   If you take six million gallons, which is about how much water that is used to frac a well, multiplied by 8 wells to the square mile,  you arrive at a one – time water use of about 48 million gallons, or 147 acre feet.   (An acre foot, or 325,851 gallons equals the amount of water which will fill a one acre area, one foot deep). Using a little “roughneck math”, on the 640 acre lease (one square mile), on which 8 wells would be drilled and fracked, there would be somewhere around 208,544,640 gallons of water available in a couple feet of the Carrizo aquifer, which is indeed quite thick. See Carrizo Wilcox thickness map below:

(The amount of water held in a vertical section of any aquifer depends on the porosity and uniformity of the formation).   Only 147 acre feet of water would be used for oil and gas drilling on the whole 640 acre section, that’s assuming it will all come from the Carrizo Wilcox, which is not going to be the case. Surface water, from large “tanks” or stock ponds will also be used as frac water, once a normal rainfall pattern returns to South Texas.

Darrel Brownlow, a geologist and former member of the Evergreen Water District, offered a presentation to McMullen County residents recently. Brownlow estimated that there will be between 20,000 and 25,000 wells drilled in the Eagle Ford shale in next 20 years, resulting in water usage of up to 300,000-365,000 ac/ft. That breaks down into 15,000 ac/ft per year or roughly 1,250 ac/ft per the 12 counties that pull water from the Carrizo Aquifer. (That’s assuming it all comes from groundwater sources and not surface sources such as ponds and that no water is recycled.)

A slide in Brownlow’s presentation noted that the 1,250 ac/ft per county includes the drilling and subsequent fracking of “roughly 80 to 100 wells per year per county.”
Brownlow stated that 1,250 ac/ft of water is about the same amount of water that it would take to farm  625 acres of corn.

I love to see detailed information such what Mr. Brownlow presented but would also like to see more studies  to confirm these numbers. For example, I’m skeptical about the amount of wells drilled per county that he offers, I think it will end up being a lot more than that. There have been over 200 permits issued for LaSalle county alone from Jan to Sept 2011.  For more reading, you can find the Carrizo – Wilcox Aquifer report here:  TCEQ Report

Is Recycling Frac Water The Answer?

Recycling frac water in the Eagle Ford shale is one way to reduce the impact on the Carrizo aquifer. There are a number of companies specializing in cleaning up used frac water, removing all chemicals, etc., from it so it can be used again for any number of purposes. This is a great technology and has been used with success in the Barnett and Marcellus shales. Companies are already setting up facilities in some areas of the Eagle Ford shale to clean used frac water. One reason that recycling frac water may not catch on as much in the Eagle Ford shale as it has in other shale plays, is due to the fact that there is favorable geology in much of the region for disposal wells to be used. Disposal wells are utilized to inject used frac and other produced water deep underground into non-productive zones far below  fresh water aquifers. The cost to treat frac water and return it to municipal water or agricultural water standards runs somewhere between $1.50 to $2.00 a barrel. (Correct me if I’m wrong and your company has developed a cheaper method).  In the end, any contaminants removed from it still must be disposed of, in disposal wells, etc.  If an oil company can frac a well with pond water or from the Carrizo aquifer for a few cents per barrel, then inject it into a disposal well for around 50 cents a barrel (add in trucking costs of about $1.00 a barrel), then the economics are simply not that favorable for treating and reusing frac water in those areas of South Texas where disposal wells can be drilled. (On a related note, it has been reported that cities such as Carrizo Springs are selling treated sewage plant water to oil companies for fifty cents a barrel).

In Texas, haulage and disposal costs average $1.47 per barrel. In the more populated East, the costs range from $1.68 to $2.10 per barrel. Source: U.S. Dept of Energy. 5/31/11

Even if treatment costs were on par with disposal costs, and used frac water was treated at a facility somewhere in the area, it still has to be trucked there, stored and then somehow transported to the next well for reuse, however far away that might be.  Six million gallons equals about 142,857 barrels, or about 1,098 vacuum truck loads just to frac one well.  I may be wrong on this one, but  the consensus I’ve been getting from  drilling consultants that I’ve spoken to is that it’s not yet economical in much of the Eagle Ford shale area to treat and reuse frac water. (At least not in those areas where the geology exists to drill disposal wells and obtain well water from the Carrizo aquifer.) This is  a subject I’m very interested in, so feel free to e-mail me if you have more insight on the economics of disposal vs. treatment in the Eagle Ford play.

It’s Not Eagle Ford Shale Drilling That Will Deplete The Carrizo

Here’s what I believe is going to be  the greater threat to the Carrizo Wilcox aquifer  in the Eagle Ford shale play area. It’s not the amount of water that is going to be used by oil and gas companies to frac wells but rather  how all of the newly drilled water wells will be used by landowners after oil drilling is over with. Landowners often end up keeping and using water wells that oil companies drill on their land. In many areas of South Texas, where the Carrizo Wilcox aquifer lies at a depth of several thousand feet, only wealthy ranchers could previously afford to  drill Carrizo wells (which could cost as much as $50,000 or more each). The game changer now is that even small landowners with a few hundred acres could possibly end up with a “free” Carrizo water well worth thousands of dollars, courtesy of the oil company. Let’s just imagine that  one new Carrizo Wilcox water well is drilled for every 2 or 3 square miles of the Eagle Ford shale play. Will the rancher or farmer then decide to put in some kind of crop, and put a high volume pump on the well and use that water for years thereafter, or will they decide to sell their water rights to a municipality such as San Antonio who offers them a deal they can’t refuse? It’s going to be interesting to see how the future “water wars” play out.

Article by Nolan Hart

The FBR Capital Eagle Ford shale report  noted that the upper side estimates were dependent on things such as improvements in drilling and recovery technologies, which enable more oil and gas to be extracted. As a general rule, every doubling of wells in a shale play has resulted in a 15-23% increase in productivity.

How Much Oil Is In The Eagle Ford Shale?

In an earlier post on this site, “How Much Oil Is In The Eagle Ford Shale”, we did some rough calculations, based on EOG Resources, Pioneer Natural Resources and Petrohawk Energy’s early estimates. Using projected EUR’s (Estimated Ultimate Recovery) numbers from those reports we estimated that the Eagle Ford shale holds about 5 billion barrels of recoverable oil. New estimates, such as the one by FBR Capital, indicate the Eagle Ford shale holds at least 7 billion barrels of oil on the low side and 20 billion barrels on the high side.

In contrast, the large East Texas oilfield that began with the famous  Spindletop gusher near Beaumont, has produced about 5.2 billion barrels from over 30,300 past and present wells. (source: Wikipedia)  The East Texas field  was previously considered the largest oilfield ever discovered in the lower 48 states. Prudhoe Bay, the largest U.S. oilfield, was estimated to have originally held 25 billion barrels. Current estimates from the U.S. Department of Energy are that there are less than 5 billion barrels of oil remaining in all of Alaska.

South Texas Changing Forever

Folks, I can’t say it enough. The small towns that you once knew in South Texas, or for that matter, larger cities such as San Antonio or Corpus Christi, are about to be totally transformed as a result of the Eagle Ford shale. If you want to imagine what many cities and towns in South Texas will look in the coming months and years, drive to Midland or Odessa  and notice all of the oilfield businesses, equipment yards, rigs, pumpjacks, etc. out there. No longer will you be driving past miles and miles of unbroken brush covered ranch land in counties such as Dimmit, McMullen, LaSalle, Live Oak, Gonzales, Atascosa and others. The landscape of a 50 mile wide by 400 mile long swath of Texas will be filled with new well locations, pumpjacks, compressor stations, and  oilfield workers busy keeping it all running. Thirty years down the line, you’ll see more of the same.

You may not like all of those changes, such as increased traffic, higher food prices, and having a huge West Texas - style oilfield all around you, but many positive things will also result from it. For one thing, South Texas schools and hospitals are about to see big improvements as the tax base grows. Over a quarter of a million new jobs could be created by the Eagle Ford shale.

Small towns and cities in South Texas are already seeing a flurry of  business activity as companies scramble for a position in the new oilfield. Halliburton is reportedly searching for a location to build a “supersite” south of San Antonio. Also,  Schlumberger, Weatherford and Baker Hughes are all considering major industrial and office complexes in southern Bexar County. Corpus Christi and Three Rivers refineries are already switching from imported oil to local crude. Refineries in the  Houston area are preparing to do the same, once large new pipelines are completed by late 2012.  It’s that big. Not to seem overly dramatic, but the Eagle Ford shale is about to change life forever for residents of  South Texas. It’s going to be a wild ride, so hang on to your hat pardner!

Article By Nolan Hart, 09/03/2011