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.

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.

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

Mineral rights in Texas are considered “real property”, and may be bought, sold, retained by the seller or passed on along with the surface property at the time of a real estate transaction.  When a landowner leases their land for Eagle Ford shale oil and gas exploration, the terms of the lease will specify a period of time, such as three to five years, in which  the oil company has the right to explore the depths leased for petroleum. In addition, a lease normally grants the mineral rights owner a portion of the revenue from oil or gas recovered, or “royalty”. Royalty agreements  such as twenty five percent are common in much of the Eagle Ford shale. The mineral rights owner stands to gain from an up front lease payment, in addition to a hefty amount of potential royalty from any future production on the property. Because of the almost 100% success rate of Eagle Ford shale wells, the prospects of  large royalty payments are often very good, if not certain, whenever drilling does come to your area.  To give you an idea of just how much Eagle Ford shale acreage is worth,  Marathon Oil Company recently paid over $21,000 an acre for leases owned by a holding company in the eastern part of the Eagle Ford shale.

With such huge potential to earn long term royalty from property with mineral rights, who in their right mind would consider selling them you might ask? The only situation in which selling Eagle Ford shale mineral rights would make any sense, would be one where the owner needed a large sum of money, greater than that which would have been paid under a lease agreement, to solve some current financial problem. For example, if the going lease payment for your area was $2000 an acre, and you were offered $10,000 an acre to sell your mineral rights, and you needed the money for a life saving operation, to avoid foreclosure, etc., then it might be worth considering. For landowners with no heirs, who are elderly and whose land may be several years away from seeing drilling, and who simply want to enjoy a few years of the “good life”, an outright mineral rights sale might make some sense. In some cases a person may own “non-participating” mineral rights. These mineral right owners don’t have “executive rights”, and therefore will not reap any up-front  lease bonus money, but may share in royalty payments once a well is drilled. It may make some sense to sell non – participating mineral rights if it looks like drilling may be many years down the road and you really need the money, however once sold, the seller loses out on any chance of getting future royalty payments.

For almost all others, and for their subsequent generations of heirs, selling Eagle Ford shale mineral rights for almost any sum is usually a colossally bad idea.  Oil and gas companies now have a very good idea (using 3D seismic and well logs) of what lies under most of the Eagle Ford shale play area. If land is leasing for a high amount in your area, chances are there’s near 100% certainty that oil or gas lies below your property.
Let’s do a little simple math and take a look at just what a bad idea selling Eagle Ford shale mineral rights might be.

Scenario 1. John and Mary Rancherfolk, of Live Oak county,  get a phone call one evening from a nice lady in Dallas who wants to talk to them about their mineral rights. She states that she works for parties who are willing to pay up to $5,000 an acre for the mineral rights under their 1000 acre ranch. John and Mary agree to a meeting and ultimately  sign over all of the mineral rights beneath their land for a lump sum payment of five million dollars. That’s more money that the couple has ever seen in their lives, and they are happy as they can be with the deal.  They’ve got a granddaughter off at college and they plan on taking care of her tuition, as well as paying off the note on the land and doing some improvements to the ranch. After taxes hit them at the end of the year, they don’t have quite as much left, but it’s still more than they’ve ever seen.  A year later, an oil company drills five Eagle Ford shale oil wells on their property. Since they don’t own the mineral rights anymore, all that they receive is compensation for surface damages, and a new Carrizo – Wilcox Aquifer water well as a bonus. They watch the oil trucks come and go, but don’t have any idea how much royalty they have given up.

Scenario 2.  The Rancherfolk’s neighbors, let’s call them Tom and Sally, sign an Eagle Ford shale lease on their 1000 acres with an up – front, $1,500 per acre lease bonus, and a royalty provision of 25% of any future production. They put 1.5 million dollars in the bank, and like the Rancherfolks, pay a hefty amount of it to the IRS, but still are able to take care of lots of things they’ve always wanted to do.  The same year that the Rancherfolks see rigs moving in on their land, drilling begins on their property as well. Five horizontal Eagle Ford shale wells are drilled, which have initial production rates of 800 barrels per day, per well.  That’s 4000 barrels of production per day, in addition to any sales of natural gas, of which Tom and Sally receive one  quarter of all sales. Oil is selling for $100 a barrel, natural gas for $4.00 per MMbtu, and their first royalty check is for three million dollars, for one month’s production. As the wells level off a bit,  and are ultimately put on pump jacks, the payments dwindle off a bit, but still amount to just over thirty million dollars the first year alone.  Over the life of the wells, and with several more being drilled over the next ten or so years, well, let’s just say that Tom and Sally, and their heirs, come out much better in the long run than the Rancherfolks did.

This example shows the need for good advice, such as that from a qualified attorney,  before entering into any agreements to sell or lease your Eagle Ford shale mineral rights.  Right now, somewhere, you can bet there is an agent talking to a landowner  in South Texas about selling or leasing Eagle Ford shale mineral rights. Beware when they come calling on you or your family and know what you might be signing away!

Article by Nolan Hart.

The lease acreage is mostly contiguous tracts, which will enable easier building of gathering pipeline networks, compressor stations, etc.  Some of this Eagle Ford shale lease area is in partnership with other oil and gas companies but will be operated by Shell.

The new Eagle Ford shale lease acreage will help boost Shell Oil’s share of North American oil and gas production which is now up to 7.8%.

As the oil spill and Deepwater Horizon tragedy has led to a moratorium on Gulf of Mexico drilling we are already seeing more money and resources being focused on the Eagle Ford shale instead of offshore projects. BP, in partnership with Lewis Energy group, now has a fifty percent interest in over 80,000 Eagle Ford shale acres. Conoco Phillips has leased over 300,000 acres.  As the offshore industry reels from drilling bans and increased regulation we will see more interest in ecologically safer areas with proven oil and gas reserves such as the Eagle Ford shale.

Shell has major positions in other North American shale plays, such as the Haynesville and Marcellus, totaling over 1.3 million acres:

Original Post:

EOG announced in a May 4th, 2010 webcast that they are planning a major oil and gas seismic survey for this summer and fall that will stretch across their 120 mile long lease area in the oil and condensate window of the Eagle Ford Shale. It was stated in the webcast that the current drilling program would be “moderated” until the results of the seismic survey in the Eagle Ford shale leasehold area was completed and fully analyzed. Investors were told not to expect any more “constant Eagle Ford news flow” until later in the year. The geophysical seismic study should take most of the summer to complete and we could possibly be seeing a very big drilling program by EOG starting in the Eagle Ford shale oil window this fall. In the past investor presentation they announced that “major production would come online in 2012″.

The only way for major Eagle Ford shale oil production to come online is for utilizing more than just six rigs, as they are presently running. Previous statements have indicated that EOG may try rotary steerable technology and multi well pads for maximum efficiency.  Current rumors in the oil patch are that they are planning a 25 rig program for this coming year.

One thing is certain and that is after paying up to $2000 or more an acre, EOG wants to hold on to much of the 505,000 acres in the oil window of the Eagle Ford shale as possible and they will have to drill quite a lot of wells in the coming three years to accomplish that, since most  of the lease terms are for that long.  Granted that many of their leases are large ranches and for many oil and gas lease contracts it only takes one well to hold the lease, but they have also leased scores of smaller parcels, down to only  a couple of acres.  The cost of losing these very small leases will not hurt them that much, and renewal offers can be made to hold them, but my guess is that EOG will start first with the larger ranches where the new Eagle Ford seismic survey data shows the best prospects and then move to drill on the smaller parcels toward the end of their three year term expiration dates. I suspect that we are talking about more than two dozen rigs running when EOG ramps up their major Eagle Ford shale drilling campaign in late 2010 and into 2011.

Oil and gas seismic survey leasing is already underway in McMullen, Dimmitt,  LaSalle, Atascosa, Karnes, DeWitt, and many other counties. If you or your neighbors have signed a lease with EOG you should be getting a call regarding permission to do an oil and gas seismic survey on your property.  For an overall picture of the entire EOG Eagle Ford shale oil and condensate window lease area, the seismic survey will be done on as many parcels as they can obtain permission for, regardless of whether they have been leased for Eagle Ford shale drilling rights or not.

What Landowners Should Consider

If you have already leased your land for Eagle Ford shale drilling I see no problem with allowing a seismic survey to take place. Here’s the dilemma facing landowners who have not already leased their property for Eagle Ford shale drilling. Should you let oil and gas companies such as EOG hire  contractors to come onto your land and use 3D seismic technology to see what is under your property for the cost of a few hundred dollars in surface damages?  This would be like allowing the person you are playing poker with peer over your shoulder and see your cards before a bet is made.   EOG could even sell the results of the seismic survey  to other oil and gas companies looking to lease Eagle Ford shale acreage that EOG has deemed unworthy.  I think it would be wise to contact an oil and gas attorney before allowing any seismic survey of your land, especially if you have not signed an Eagle Ford shale lease yet.

Nolan, May 14, 2010

See updated info above.

For those who have been wondering what EOG Resources is up to in the Eagle Ford shale, a recent press release has shed some light on their plans.

EOG Resources has so far been hush – hush about their plans for drilling in the Eagle Ford shale.  On the company website they announced several weeks ago that they were aquiring acreage but were going to keep plans for development quiet until most of the leasing had been done. Now that it has they are letting the cat out of the bag.

Now information is surfacing, such as this from an official press release, that they are planning a major drilling program in the oil window of the Eagle Ford shale with ”significant production” coming online in 2011.

EOG declared the Eagle Ford shale a ”major oil discovery“   in this April 7 press release.  CEO of EOG, Mark Papa was quoted as saying that the Eagle Ford shale was, in his words “one of the most significant United States oil discoveries in the past 40 years”.  EOG has estimated that the Eagle Ford, as an oil discovery, will rank #6 in size of all time giant oil fields in the U.S. just after the Bakken Shale. The largest would be Prudhoe Bay.

EOG hs aquired just over a half millon acres of South Texas leases across six counties.

Sixteen dileneation wells were drilled over a 120 mile trend to determine the extent of the play.

“Based on initial drilling and production results, as well as technical and core analysis, the estimated reserve potential on EOG’s 505,000 net acre position in the oil window is approximately 900 million barrels of crude oil equivalent (MMboe), net after royalty (NAR).”

(NAR refers to how much the company keeps after giving the landowner a percentage of production.)

EOG is currently operating six rigs,  drilling more wells over a large area of the Eagle Ford shale in the upper portion known as the “oil window”. Due to depressed natural gas prices, the oil rich part of the shale may be more intensley drilled than the southern gas portion.

Many Potential Well Locations

EOG has estimated that there are 2,840 potential well locations in the 505,000 it holds in the oil window of the Eagle Ford shale.  They estimate that 75% of the acreage is drillable. They are basing all estimates of production on well spacing of 125 – 140 acres per well.

EOG has stated that there is “great rock quality with high consistency” in the play, with wells 30 miles apart showing similar porosity of between 4 – 11% and permeability of 40 – 1,300 Nd.

Leasing is underway in the upper counties including Frio, Atascosa, LaSalle, McMullen, Zavala, Dimmitt, Live Oak, Wilson, DeWitt, Gonzales, Karnes, Dimmit and Webb counties.

EOG has a good track record of drilling horizontal wells in the Barnett Shale and Bakken Shale. EOG investors as well as landowners who just signed leases should be pleased with this recent news about the Eagle Ford shale oil discovery.

Update: In a May 4 EOG webcast it was stated that the current drilling program in the Eagle Ford shale would be moderated until a major 3D seismic project was completed and the results analyzed. EOG has drilled their 17th Eagle Ford shale well, the Harper 4H, which is producing 602 Bbl of oil per day and 650 Mcf of gas. “Don’t expect a constant Eagle Ford news flow from EOG until late this year” it was stated in the webcast.
EOG expects to average only 6000 Barrels per day equivalent per day of oil from the Eagle Ford in 2010 with much more production coming online in 2011. This indicates that a major drilling program will ramp up in late 2010 when the most productive areas of the acreage are identified and targeted by 3D seismic surveying.

Update:

Despite persistent rumors of a 25 rig program, Oil and Gas Journal reported the following on August 9th, 2010:

(From Oil and Gas Journal)
HOUSTON, Aug. 9 – EOG Resources Inc., Houston, will ramp up its operated rig fleet to 12 at the end of 2010 and 14 in 2011 from five at present as it better understands the South Texas Eagle Ford shale from interpreting 3D seismic along the 120-mile oil trend in which it holds 505,000 net acres.

EOG management said it is still early days in the play, but the Eagle Ford reservoir seems to be working on expansion drive toward 3-4% estimated ultimate recovery. Unresolved are determining optimum spacing, locating wells, areas that will be productive from Upper and Lower Eagle Ford or just one, and other issues.

EOG plans to drill 245 gross Eagle Ford wells in 2011 compared with 111 this year. Even so, the formation will be a large contributor to oil production growth in the second half of 2010, as EOG has drilled and completed 31 wells and has 25 awaiting completion.

Recent company Eagle Ford wells had initial production rates of 1,033, 1,002, and 625 b/d of oil plus rich gas, and the first wells in Wilson County came on at 707 b/d and 836 b/d. EOG has 100% interest in the wells.

EOG raised its 2010 capital expenditure budget by $500 million. Of that, roughly $270 million is for Eagle Ford crude oil related production and midstream facilities the company had previously planned to contract to a third party. EOG laid the change to timing and cost issues.

EOG’s exploration staff is clamoring to test the Austin chalk and Buda formations on the company’s Eagle Ford acreage, said Mark Papa, chairman and chief executive officer. Papa said EOG also sees South Texas production contributions from the Frio and Vicksburg formations.

Update #2:

HOUSTON, Aug 6 (Reuters) – EOG Resources Inc (EOG.N) said on Friday it plans to sell about 180,000 acres in U.S. shale plays as part of the oil and gas company’s effort to increase funds for oil exploration.

EOG will sell 117,000 acres in the Eagle Ford Shale in South Texas; 51,000 acres in the Marcellus Shale in Pennsylvania; in 15,000 acres in the Haynesville Shale, Mark Papa, the company’s CEO, told analysts on a conference call.

“We’re so long on acreage relative to what we can logically develop in a reasonable period of time,” Papa told analysts.

There is no word yet on where the acreage EOG is selling is located but statements from Papa indicate that because EOG will be “focusing more on oil production”, the acreage will not be part of what it holds in the oil window. It would be hard for me to imagine them giving up much acreage in the lucrative oil window. It could be this is dry gas acreage farther south and west.

Companies such as EOG Resources and Petrohawk Energy have decided to focus more on liquids than on natural gas. To do this will require a lot of capital and the company has realized that it is in way over its head when it comes to drilling up Eagle Ford shale acreage, which is mostly on three year lease agreements, before those leases expire.  To exploit what they have they will need large amounts of capital, something the latest Eagle Ford shale acreage sale aims to remedy.

The size of an oil or gas play may be only a few hundred acres or as is the case with the Eagle Ford shale, Haynesville shale, Barnett shale and Marcellus shale, cover hundreds of thousands of acres over a wide region.

A shale gas play, such as the ones mentioned above, is simply a discovery of oil or gas in shale rock that is significant enough for oil and gas companies to launch a campaign of leasing and subsequent exploration. In the case of the Eagle Ford shale it is turning out to be both a shale gas play and and oil play.

What Is Shale Gas?

Shale is a sedimentary rock that is generally formed as particles of sediment settle out in calm water. Shale can be formed in shallow inland waters or deep ocean basins. Many of the shale formations in the United States, such as the Marcellus shale, were formed during the Devonian period, around 390 million years ago.

The rock found in the Eagle Ford shale, which is the focus of this blog, was formed in a marine environment during the Cretaceous period, approximately 145 to 65 million years ago. It was during the Cretaceous period, following the Jurassic period, that many of the worlds limestone formations were laid down. Cretaceous literally means “chalky”, taken from the German word for chalk,  Kreide. The Cretaceous period was a time of warm climate and high seas. During the Cretaceous period billions of tons of CO2 were “sequestered” by marine organisms and eventually returned to the earth in the form of sediments.

Shale rock is generally high in organic content. Once covered up by other sediments and buried over millions of years, heat and pressure begin to work on these sediments and oil and gas are formed. Some of the oil and gas may begin to migrate upwards, to layers of sandstone and porous limestone where it becomes trapped. These are considered conventional oil and gas reservoirs and shale is often the “source rock” or original source of the hydrocarbons. In some cases, as in the Eagle Ford shale play, a significant quantity of oil and gas remain in the shale rock. Natural gas and oil that occur in shale are called “unconventional”.  Now with new horizontal drilling and hydraulic fracturing methods it is possible to extract that oil and gas. “Unconventional” gas is quickly becoming the new norm.

The illustration below shows how South Texas looked during the Cretaceous. It was covered by shallow warm seas. It was during this period that the Eagle Ford shale was deposited.

Below is an illustration of what a shale formation looks like underground and how a horizontal well is drilled.

Shale gas, from rock formations such as the Marcellus shale, Haynesville shale, Barnett shale and now the Eagle Ford shale, is an important energy resource for the United States. Now thanks to these “discoveries” or moreover the advances in technology that make recovery of oil and gas from shale possible, we have over 100 years worth (and growing) of natural gas supply in North America. Hopefully our elected officials will wake up to this new reality and quit wasting our tax dollars on things like corn ethanol and “clean coal” and instead focus on converting our vehicles and power plants to use abundant natural gas.

Article by Nolan Hart

Here is a good book to get if you are considering leasing your land for oil and gas exploration. It’s not cheap but could save you thousands in the long run.

The name of the oil and gas play is frequently misspelled as “Eagleford”. The correct spelling is what is seen on this website.   The Eagle Ford shale takes it’s name from the small town of Eagle Ford Texas, where it outcrops in North Texas near Dallas.

The following map is from Ross Smith Energy Group . They do not sell maps to the public.  It appears here with their permission.   This Eagle Ford shale map shows the trend from Mexico (where it obviously continues across the border as well) to East Texas. It shows the low pressure, oily section in the northern region, the condensate section in the middle and the dry gas section at the lower half. Although it is difficult to read the gray areas are Austin Chalk producing areas. Wherever you find Austin Chalk production you are likely to find Eagle Ford oil as well.

Here is a map from EOG Resources showing the oil, gas and condensate zones of the Eagle Ford Shale as well as some initial production rates. (Note, IP, or initial production rates should not be confused with long term production rates). You can click on the map for full size.

Below is a map from the U.S. Energy Information Administration. The map is a little out of date when it comes to showing well locations, since dozens of new Eagle Ford shale wells have been drilled since it was made. It does however provide a good picture of Eagle Ford shale thickness and extent.

The following Eagle Ford shale map from the Texas Railroad Commission shows counties with permitted and completed wells as of August, 1, 2011.

Below is an Eagle Ford shale map showing the depth of the top of the formation.

Below, Eagle Ford shale thickness maps from Petrohawk Energy. Thickness in feet of the Eagle Ford shale in Atascosa, Gonzales, Wilson, Karnes and DeWitt counties is shown.

The map below, from Marathon Oil, shows the Eagle Ford shale divided into four zones, dry gas, wet gas, volatile oil and black oil. While the distinctions between “black oil” “volatile oil”, condensate and “wet gas” are something even petroleum engineers can’t seem to agree on, basically “volatile oil” is lighter oil that evaporates faster than heavier crude. Lighter crude oil (higher API gravity) typically trades at premium prices since it is more easily refined into gasoline, etc. Marathon Oil purchased the acreage shown in blue from Hilcorp Resources Holdings for approximately $20,000 an acre.

The Carrizo Wilcox aquifer is an important source of water for much of the area where the Eagle Ford shale lies, and a primary source of frac water used in completing wells. Below is a map of the Carrizo water sand.

Below is a chart showing the Cretaceous geology of South Texas, including the Eagle Ford shale formation. The Pearsall shale is located deeper than the Glen Rose formation at the bottom of the chart.