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

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.

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

Source: Rosetta Resources.

EOG Resources has already made a request to the Texas Railroad Commission for 80 acre spacing in the Eagleville field. If that was applied to the 550,000 acres they hold in the oil and condensate windows we could ultimately see 6,875 wells drilled by EOG alone.

Number Of Ultimate Eagle Ford Shale Wells Grossly Underestimated

In a study of the economic impact of the Eagle Ford shale published in Feb, 2011 by the University Of Texas At San Antonio’s Institute For Economic Development, it was estimated that 4,890 wells would be drilled in the Eagle Ford shale between 2010 and 2020. The study estimated that 305 oil wells and 102 gas wells would be drilled in 2011. If we are to believe company reports, EOG Resources alone plans to drill 250 wells this year, Hess (25), Petrohawk (85), Rosetta Resources (25), ConocoPhillips (150), Chesapeake (undisclosed but probably around (200) with 17 rigs running), SM Energy (70), Murphy Oil (29). That’s an estimated 834 Eagle Ford shale wells to be drilled in 2011, and that doesn’t include Marathon Oil, Apache and a half dozen other companies who are active in the play. The UTSA study has vastly underestimated the number of Eagle Ford shale wells which will be drilled due to a simple mathematical error. The study based the number of future Eagle Ford shale wells on  the following calculation:

Ln(Drilling)=1.61+E*Ln(HenryHubprice). E= Price Elasticity Of Drilling = 1.

(Don’t ask me how the formula works. I’m just reprinting it here from the published study.)

The study used the Henry Hub price of natural gas as the basis of drilling activity. The Eagle Ford shale is now an oil play, with natural gas drilling in the dry gas window only being done to hold leases. The formula may apply to the dry gas window, but definitely not to the rest of the play. Wells in the volatile oil window have proven to be far more productive than was imagined even a few months ago.

Had the study been based on the price of oil instead of natural gas, it might have been more accurate. Rather than 305 wells we should see somewhere around 1000 new Eagle Ford shale oil and gas wells drilled in 2011.

How Much Oil Will The Eagle Ford Shale Produce?

Another thing that the UTSA study severely underestimated was Eagle Ford shale oil production.  Bentek, an energy consulting firm, reported in August of 2011 that Eagle Ford output had more than doubled in the last two months to 160,000 barrels per day and was on track to grow fivefold by 2015. The current rate of production would equal 58 million barrels a year. Five times that, what Bentek forecasts for five years down the line, would be 292 million barrels of oil a year from the Eagle Ford shale. That’s quite a bit more than the 8.7 million barrels the UTSA’s study forecast for 2011, and about 242 million barrels more than what it predicted for 2015. As each month goes by, Eagle Ford shale production figures continue to blow all of the previous forecasts out of the water. Just wait until the network of pipelines currently being constructed in the Eagle Ford shale area is completed and see what happens to daily production figures! Takeaway ability is currently hampering production and some wells are on restrictive chokes waiting for pipelines to be ready.

The Texas Railroad Commission has already issued 2,301 permits for Eagle Ford shale wells (as of August 1, 2011.) Where this play goes from 2011 is going to be mind boggling. The price of oil doesn’t appear to be going lower in the long term due to demand by China and the rest of the developing world. By the end of it all, a wide swath of South Texas’s underground landscape is going to look like the illustration of the Gates Ranch above.

Article By Nolan Hart

The company came to South Texas looking for a shale formation analogous to the Haynesville shale (located in Texas, Oklahoma and Arkansas), where they had good success with completions involving multi-stage frac jobs on horizontal wells. What they found  was ultimately proclaimed “the largest domestic oil and gas discovery in over forty years.  In the beginning, Petrohawk’s focus was on natural gas in the Eagle Ford. Based on seismic surveys and well logs they began acquiring what appeared to be the best acreage prospective for natural gas. Ironically,  natural gas prices in North America became depressed, due in part to the success of companies like Petrohawk Energy, who were drilling horizontal wells in gas rich formations such as the Haynesville shale.  As natural gas prices fell, the value of oil and natural gas liquids continued to increase. Large volumes of oil and natural gas liquids were discovered in the middle and upper areas of the play, and the leasing game abruptly changed.

As more wells were drilled in the play it was determined that the central and upper part of the Eagle Ford was where the money was to be made.  In a strategic move that has been widely hailed as a “major coup” in the oil and gas industry, EOG Resources began to stealthily lease up all of the “wet” Eagle Ford shale acreage that they could get their hands on, much of it at prices under $500 per acre. EOG Resources soon overtook Petrohawk as the largest leaseholder in the Eagle Ford shale, (with currently over 600,000 net acres) and became the biggest liquids producer. In a game of “catch up”, Petrohawk Energy’s Eagle Ford shale strategy soon shifted to gaining more acreage in the oil and gas and condensate windows of the play. As the estimated ultimate recovery potential of wells in the oil and condensate bearing zones of the Eagle Ford was realized, lease rates soared to as high as $8000 an acre in some of the “sweet spots”. Currently Petrohawk Energy’s acreage in the Eagle Ford shale is around 332,300 net acres.

Map Of Petrohawk Energy’s Eagle Ford fields and shale thickness.

The Hawkville Field

Petrohawk Energy named the discovery field the “Hawkville Field” and this name was adopted by the Texas Railroad Commission. This field, located in LaSalle and McMullen counties, comprises the bulk of the company’s Eagle Ford shale holdings at 236,000 acres. Much of the acreage is in the “wet gas” window of the play, with shale thickness, shown in red, of up to 375 feet. 2010 year end proven reserves for the Hawkville field were 627 Bcfe.

From the company website:

“The wells have an average true vertical depth that ranges from 10,500 feet to 12,500 feet and they are drilled with horizontal laterals currently ranging from 5,000 feet to 7,000 feet. The wells are cased hole completed and are currently being fracture stimulated with an average of 18 stages. There are currently 27 wells which produce condensate with yields ranging from six barrels per million cubic feet (Bbls/Mmcf) to 199 Bbls/Mmcf and had an average initial producing rate of 311 barrels of oil per day (Bo/d). There are currently 23 wells which produce dry gas and had an average initial producing rate of 8.6 million cubic feet of natural gas per day (Mmcf/d). We had 16 operated wells and four non-operated wells that were pending completion and three wells that were drilling in this field at year-end.”

In the Hawkville Field, Petrohawk Energy is having good success with the HiWay fracturing method developed by Schlumberger. The HiWay technique is reported to produce higher initial production rates and long term flow rates.  The HiWay fracturing technique combines “fit – for – purpose fracture modeling”, specialized frac fluids and “high frequency proppant propulsion”.

Black Hawk and Black Hawk Extension

Petrohawk Energy has a leasehold of approximately 69,000 net acres located in Karnes and DeWitt Counties, Texas.

“The Black Hawk Eagle Ford Shale pay thickness is over 170 feet. The wells have an average true vertical depth that ranges from 12,000 feet to 13,500 feet and they are drilled with horizontal laterals currently averaging over 5,500 feet. The wells are cased hole completed and are currently being fracture stimulated with an average of 18 stages. There are currently 12 wells which produce condensate with yields ranging from 213 Bbls/Mmcf to 517 Bbls/Mmcf and had an average initial producing rate of 1,170 Bo/d. We had 15 wells that were pending completion and five wells that were drilling in this field at December 31, 2010. The gross production from this field is currently 22 Mmcf/d plus 8,200 Bo/d. As of December 31, 2010, proved reserves were approximately 109 Bcfe, of which approximately 34 percent were classified as proved developed and 72 Bcfe as proved undeveloped. The proved reserves include 27 proved developed wells and 41 proved undeveloped locations. During 2010, we drilled 29 wells with no dry holes and there are 85 wells budgeted for 2011.” 

Petrohawk acquired approximately 10,500 net acres from a private company in December 2010. This new acreage is to the west/southwest of Black Hawk field. Petrohawk Energy has a 96 percent working interest and 79 percent net revenue interest in the acreage. There is currently no production but the first well is planned for 2012.

Red Hawk Field

Petrohawk Energy’s Red Hawk field consists of 77,000 net acres in Zavala county. Eagle Ford shale thickness there is from 100 – 140′. Currently there are three wells with initial production averaging 375 barrels per day, with an inconsequential amount of natural gas. Five wells are planned for the Red Hawk field in 2011.

Acquired By BHP Billiton

The Australian mining firm BHP Billiton recently acquired Petrohawk Energy for a sum of approximately 12 billion dollars. At this price, Petrohawk Energy’s Eagle Ford shale acreage was valued at approximately $15,000 per acre. The company has come a long way from its humble beginnings as an independent energy company called Beta Oil and Gas that was started in Houston in 2003.  We can expect Petrohawk to continue to be one of the leading natural gas, oil and natural gas liquids producers in the play. Long term takeaway agreements have been reached for Eagle Ford gas and liquids, including a joint venture with Kinder Morgan Energy Partners. The Kinder Morgan – Petrohawk Energy Eagle Ford joint venture will include 280 miles of gas gathering lines and 112 miles of gas condensate gathering lines.

For more about Petrohawk Energy’s Eagle Ford shale operations and news, you can visit their Website

Article by Nolan Hart.

One of the most common questions that  landowners who have signed Eagle Ford shale oil leases ask is  “when will they drill an oil well on my land?’

In the oil business, decisions are most often made with two things in mind, maximizing profit and minimizing risk. One of the biggest risks for oil companies in the Eagle Ford shale play at the moment is having leases expire, with no oil and gas production to hold them, then having to face a much more competitive market to re-lease that acreage. Once a well is drilled, the lease is “held by production”, but with so much acreage to drill up, oil companies simply won’t be able to get to all of it before leases expire or come up for renewal. Many Eagle Ford shale oil leases contain an option for the oil company to extend them when the primary term expires. For example, the contract may enable the oil company to pay the same amount per acre to hold the lease for another two years. On large ranches, it may cost an oil company too much to renew leases, so they will make every possible effort to drill a well and “hold by production” the acreage. This is especially true in areas where the price per acre of Eagle Ford shale leases has been driven into the thousands.  If you have several hundred or several thousand acres in one of these areas, and you signed a lease with a primary term of three years,  there is a good chance that you’ll see a rig move in before it expires so the company doesn’t have to pay any more to hold the land.

Oil Companies Must Clear Up All Title Issues First

Before drilling begins, oil and gas exploration companies must clear up all title issues related to the properties involved. If a number of  parcels of land are involved in the proposed unit, it may take several months to track down all of the information required to establish genuine ownership of the minerals / surface. Tracts of land must not have issues such as disputed ownership or back taxes. In the case of property that has  a quitclaim deed, (the lowest quality deed), the company may need to get affidavits from neighboring landowners to help validate the claim of ownership. This is necessary to avoid large lawsuits once royalty payments, surface damage, etc.,  becomes an issue.

There are other factors at play in the Eagle Ford shale right now that may be affecting drilling in your area.  These factors include the ability of the Texas Railroad Commission to issue permits, the availability of drilling rigs, frac water, sand, road material, oil and gas pipelines and trucks, etc. “Takeaway capacity” or the ability to get oil and gas from new wells to market, will be an issue well into 2012, until new pipeline networks are finished. Also,  permitting for new wells has seen delays due to a staffing shortage at the RRC, which is down to 625 full time employees from 704 in ’09. Update: The Texas RRC has noted that as of Sept, 2011 drilling permit processing time is, according to them, “1 business day for expedited permits and 3 business days for standard permits.”

Putting On A Show For Wall Street

Some landowners, such as those with EOG Resources leases in McMullen and LaSalle counties, have been perplexed to see drilling rigs show up, then move on down the road a few months later.

According to one oil company executive that I spoke to, one of  the motives in relocating assets is to drill enough “super wells”  and get them online as soon as possible to impress Wall Street investors. This is most likely the reason that companies such as EOG Resources have shifted rigs away from the western Eagle Ford play toward counties to the east. According to the Schlumberger rig count, EOG Resources had, as of July, 28, 2011,  9 rigs drilling in Gonzales county,  6 in Karnes county, and 2 in Wilson county, (the eastern side of the play). At that time there were only two rigs drilling for EOG Resources in LaSalle County and none in McMullen or Dimmit counties. EOG Resources holds thousands of acres in those counties, with proven reserves. However, in order to focus on “big producers”, they have moved almost all of their rig fleet to the east, where they are bringing in wells producing more barrels of oil than those in the western province. In Gonzales county, EOG has wells such as the Hansen – Kullin #3H, which is producing 1,538 barrels a day, with shorter laterals than those in the west. While there have been some big wells drilled in LaSalle, Dimmit, McMullen and other counties to the west, those in the eastern side of the play are on the priority list. The aim is to boost production numbers and keep the investor’s money flowing in. For landowners wanting to see an Eagle Ford shale well on their property, patience is a virtue. Rumors are in the air of “massive drilling programs”, by the main players in the Eagle Ford shale, once a network of new pipelines is completed in 2012.

Update: 09/19/2011.  Judging from the two dozen or more new drilling permits recently approved for EOG Resources in LaSalle and McMullen counties, a shift of rigs back to the west side of the play will occur in the coming months in order to “hold by production” some of the larger leases, which are about to come up for renewal.

By Eaglefordshaleblog.com editor Nolan Hart, 07/28/2011

Below, new pipeline originating at crude gathering terminal in Gardendale, near Cotulla, TX.

Ultimate Recovery Potential Of Eagle Ford Shale

Already being called the sixth largest oil discovery in U.S. history, the true picture of how much oil will be recovered from the Eagle Ford shale is still evolving. EOG Resources analysts see well over a billion barrels recoverable from their 600,000 acre leasehold area. Enterprise Products Partners, one of the major pipeline companies in the play, estimates over 3 billion barrels of crude recoverable in the Southwestern part of the Eagle Ford shale alone.  Figures of between 3 and 7 billions barrels of recoverable liquids have been tossed about, and the numbers seem to be changing every week to the upside. By the way, the Tiber oilfield, BP’s discovery where the Deepwater Horizon tragedy struck, is estimated to hold 250 million barrels of oil, a small fraction of what the Eagle Ford contains.  Will the Eagle Ford shale eliminate foreign oil imports? According to the EIA, we use about 6.99 billion barrels of oil per year, so that’s not likely. Still, what’s been discovered in South Texas is a heck of a lot of easy to extract oil, all in one continuous field. Eagle Ford shale production, as well as what is coming online from similar shale discoveries, such as the Niobrara and Bakken shales, are helping to reverse the decline in U.S. oil production for the first time since the 1970′s.

Price Differential

One problem that is plaguing oil producers in the Eagle Ford shale, Permian Basin and other landlocked areas, is the price differential between WTI (West Texas Intermediate) and other valuations such as LLS (Light Louisiana Sweet). LLS is a waterborne, premium quality Gulf Coast crude that has been priced as high as $20 over WTI in the past year. New pipelines and rail facilities may help to reduce this price differential.

WTI vs. LLS spread in dollars. (West Texas Intermediate vs. Light Louisiana Sweet crude)  Courtesy of Bloomberg.

Where Will Eagle Ford Shale Oil Go?

Once all of these pipelines are completed, where will all of that Eagle Ford shale oil go?

As of July, 2011, Eagle Ford shale oil production (including condensate) stands at around 100,000 barrels a day. That figure is expected to rise to over half a million barrels a day by 2012.  Enterprise Products Partners is currently building a 350,000 b/d pipeline network which will transport oil to Gulf Coast refiners as well as into larger pipeline networks which will send it on to the Cushing hub in Oklahoma. At Three Rivers, Valero is ramping up their refining capacity to be able to handle 60,000 barrels per day by the end of 2011. Corpus Christi refiners such as Flint Hills Resources are building pipelines from the Eagle Ford shale to Corpus Christi. (A 250,000 b/d pipeline by Flint Hills, 120,000 b/d line by Koch Pipeline, and 100,000 b/d pipeline by Nustar Logistics -Velocity Midstream Partners are all in the works to deliver Eagle Ford shale to Corpus Christi Refineries.

In addition to Corpus Christi refiners, a large amount of Eagle Ford shale oil will be heading to Houston refiners via Enterprise Products Partners 350,000 b/d pipeline.  The question is, can Texas refineries handle it all? I came across an interesting article, Eagle Ford Shale Crude Destined For Export?,  which suggests that because Gulf Coast refiners are set up to handle heavier, higher sulfur content crude, a portion of Eagle Ford shale production may end up getting shipped to overseas refiners.  Eagle Ford shale crude averages between 42 – 60 API (gravity). Gulf Coast refiners are set up to make the most of heavier oil, from 29-30 API with high sulfur content, and turn it into products ranging from gasoline to asphalt. Eagle Ford shale crude can be blended into the mix of foreign oil, but only to a certain point, after which refiners will either need to modify existing equipment to handle lighter crude or turn it away.  Why not ship it via tanker to East Coast  refiners, who are better able process light sweet crude? It seems that a law called the “Jones Act”, may stand in the way of shipping domestic crude via U.S. flagged vessels. Because of the current wide spread between Brent crude and WTI, which has been as high as $20 or more a barrel, we could see ports such as Corpus Christi begin to ship oil abroad instead of receiving it.  Go figure, we find the biggest oilfield in over forty years, and we end up shipping its production overseas.

Updates: 08/05/2011-08/26/2011

Subsidiaries of EOG Resources have entered into an an agreement with Nustar Logistics to build a 70,000 barrel a day train offloading facility in St. James, LA. The new facility is part of NuStar’s 8 million barrel crude oil terminal at the St. James hub. The facility will be able to offload one 70,000 barrel train per day. The facility will handle EOG Resources crude shipments from the Eagle Ford, Bakken and other shale plays in the U.S.

U.S. Development Corp. announced in August that it will begin construction of 5 new rail facilities for handling crude from the Eagle Ford shale, Bakken shale and other areas. The terminals will be capable of handling 65,000 barrels each and will be located in South Texas, the East Coast, West coast and other locations.

Update 08/09/2011 (Reuters)  Shell is considering reversing the the Houma to Houston pipeline to bring Eagle Ford shale crude from the Houston and Port Arthur areas to Louisiana. The line has so far been bringing Louisiana crude to Texas, but with the huge amount of Eagle Ford crude entering the system it now makes sense to reverse the flow in the opposite direction.  The reversed “Ho Ho” line, as it is nicknamed, may be carrying 300,000 barrels of crude by early 2013.

Article by Nolan Hart, 7/22/2011