More On The Barnett Shale Gas Play, Devon Energy

Very interesting. New technology, horizontal drilling, geology, high stakes, big money, Texas. Stay tuned. Note: This article was written "way back" in 2005.
Peter

Devon Energy Marks Milestone in Barnett Shale Play
Aug. 8--OKLAHOMA CITY -- In the third week of July, Devon Energy of Oklahoma City lifted its one-trillionth cubic foot of natural gas from the Barnett Shale field near Fort Worth.

A "T," as energy people call it, is a milestone under any condition and more so in this case because it represents almost 70 percent of the 1.45 trillion cubic feet of natural gas taken from the Barnett Shale field since 1993. It puts Devon on track to repeat as the biggest gas producer in the Barnett Shale, Texas' largest gas field, and as the top natural gas producer in Texas.

It was also a payoff for Devon, the acquisitive company that has become both the pioneer and biggest player in drilling and production in the Barnett Shale field.

Today, the company has 18 rigs working in the Barnett Shale. Most significantly, five of them are in Johnson County, south of Fort Worth. For Devon, the expansion beyond its original base in Wise, Denton and northern Tarrant counties marks a significant turn in the investment it made in 2002 when it bought Mitchell Energy and its pioneering base in the Barnett Shale for $3.5 billion.

Since 2002, Devon has drilled almost 2,000 wells in the Barnett Shale, more than doubling Mitchell's 2002 production to the current 560 million cubic feet a day. Up to 1,000 more wells could be drilled on the company's leased acreage in western Wise County, as well as Johnson, Parker and Hood counties.

The Barnett Shale is merely the highest-profile field in which Devon operates. The company, through its 2002 purchase of Ocean Energy of Houston, was already a player in the Carthage Field in East Texas, the state's second-most productive field. Devon also has significant acreage in the Permian Basin in West Texas and in the old South Texas gas fields near the Mexican border, much of it acquired when it bought Pennzoil's exploration and production unit in 1999 (a purchase that had eluded Fort Worth-based Union Pacific Resources two years earlier).

In addition to the 20 offshore Gulf of Mexico wells Devon plans to drill this year, the company is a big player in Canada and the Caspian Sea region. It is also making inroads in China. Still, 88 percent of its production is in North America.

This year, Devon received permission from the Texas Railroad Commission to reduce the spacing between gas wells from 40 acres to 20. Although that hardly brings back the early 20th Century practice of drillers putting derricks literally against one another, Devon hopes that the closer spacing will add production.

Devon, too, is going back to some of its older wells and refracturing them. Fracturing involves injecting water mixed with fine sand at high pressure to create hairline cracks in the tight shale. More than any other technology, it has made the difficult Barnett Shale play possible.

A "frac" is done after the well is first drilled, and Devon thinks that it can reverse the inevitable production decline (of up to 50 percent) that sets in over the first two or three years of a well's life.

"We've done some refracs in Wise and Denton counties, and we find that we can take a well that originally produced 1.5 million cubic feet a day and had declined over a few years to about a third of that, and then bring the production back to the original level," said Brad Foster, who heads Devon's North Texas operations.

Devon has kept its head down in Texas, putting its Barnett Shale field offices in Bridgeport and Cleburne rather than in a higher-profile setting in Fort Worth. The company reflects the low-key style of Chairman Larry Nichols.

Nichols, 63, is not the kind of Oklahoman to throw his hat into the air and start singing about the wind whipping down the plain at the thought of a Sooner State company being Texas' biggest gas producer.

Nichols, who has a geology degree from Princeton University and a law degree from the University of Michigan, once clerked for the late Chief Justice Earl Warren. Nichols was working at the Justice Department as an assistant to William Rehnquist, who is now chief justice, when he returned home to join his father, John, in the family's energy-investment firm.

Nichols may come from a pioneering Oklahoma family, but he isn't one to proclaim an Oklahoman dominance over Texas, at least in gas production.

"It's a nice thing to be Texas' biggest producer because it means we're doing good work," he said. "But it doesn't go any farther than that."

Independent energy analyst Kurt Wolff is among Devon's boosters. He describes the firm as "an independent that is still being run by the chief executive who has built its great long-term record."

At the time Larry Nichols joined the family firm, John Nichols, an accountant by training, had run it for two decades.

"Dad thought this was a great time to begin raising money in Europe for energy investment in the U.S.," Larry Nichols said.

The newly named Devon Energy ("We didn't want to call it 'Nichols Energy,' " Larry Nichols recalled), did a nice -- although quiet -- business investing in various drilling and production projects, mostly in the Southwest, but also in West Virginia gas fields. The energy boom of the late '70s and early '80s benefited Devon Energy nicely. Along the way, John Nichols, 91, who remains a venerable presence in Oklahoma City, turned over the company reins to Larry.

The younger Nichols proved to be an aggressive acquirer of properties, but it was a decision to not do something that saved Devon. In 1982, the company was poised to join the so-called "Deep Anadarko" play in southwestern Oklahoma. The industry was abuzz about the play, which was 25,000 feet deep, and its supporters said it was going to be the next big thing.

But the Deep Anadarko didn't feel right to John and Larry Nichols. The industry bore all the signs of a boom about to go sour: overproduction, flagging demand and a vast oversupply of drillers. So the Nicholses decided to sell instead of going deep in the Anadarko.

The sale saved Devon when the price of a barrel of oil plunged from $34 to $10 over the next three years, taking three-quarters of the U.S. domestic energy industry with it. Devon Energy was still standing and able to go public in the late 1980s in order to make its mark as a pioneer in the coal-bed methane gas play in the San Juan Basin of New Mexico.

Devon's success in the San Juan Basin and other domestic fields gave it the capital to go after some of the goodies that were placed on the table as the energy industry consolidated during the 1990s doldrums: the venerable Kerr-McGee company of Oklahoma in 1996; Northstar Energy in 1998, which gave Devon a major foothold in Canada; Pennzenergy in 1999; Santa Fe Snyder (co-founded by Fort Worth oilman John Snyder) in 2000; and Anderson Exploration in 2001.

The San Juan Basin success also gave Devon the confidence that it could handle a new, unconventional natural gas play. It champed at the bit when Mitchell Energy of Houston began shopping itself in 1999.

"Mitchell was interesting because it had opened the Barnett Shale in North Texas, and we watched it closely," Larry Nichols said. "In 1999, when we first talked with them, we didn't think we were quite ready. Two years later, we were."

When Devon made the $3.5 billion deal to buy Mitchell, the Oklahomans made it clear that the Barnett Shale was, as Nichols said, "the prize of the transaction."

At the time of the purchase, Mitchell's aggressive beginning in Wise and Denton counties had resulted in 400 wells. By mid-2005, Devon had more than 2,000 wells in the Barnett Shale and had produced a trillion cubic feet of gas. Most important, as Wolff, the energy analyst notes, "Devon caused a lot of other producers to look hard at the Barnett Shale, and most of them eventually got into the play. But Devon was there early."

-----

To see more of the Fort Worth Star-Telegram, or to subscribe to the newspaper, go to http://www.dfw.com.

Copyright (c) 2005, Fort Worth Star-Telegram, Texas

Distributed by Knight Ridder/Tribune Business News.

Just A Glimpse At The Potential Of Horizontal Drilling

Natural gas is an abundant, clean-burning source of energy, independence, jobs, and a recovering economy. The following is an article describing its abundance. Of course this assumes the usage of horizontal drilling. Read on.
Peter



UGI: Unconventional gas wealth seen in world's basins

G. Alan PetzetChief Editor-Exploration
FORT WORTH, Sept. 30 -- Sedimentary basins in the US appear to contain a volume of technically recoverable unconventional gas that is 10 times the ultimately recoverable volume of conventional gas.

All resources are logarithmically distributed in nature, and the lower quality deposits need more expenditures and better technology to develop economically, Stephen A. Holditch of Texas A&M University told the opening session of Oil & Gas Journal's Unconventional Gas International Conference & Exhibition in Fort Worth Sept. 30.

Results of the studies of eight US basins are being configured into software that can be used as advisory points as operators begin to drill, complete, stimulate, and produce shale, tight sands, and coalbed gas reservoirs outside North America, where almost all of this type of drilling has occurred so far, Holditch said.

Based on the findings, which imply that vast quantities of gas can be produced in the world's basins, even Saudi Arabia's state oil company Saudi Aramco has started a tight gas sands research group, Holditch said. Holditch and a large group of his students plan to release more details of the still incomplete findings at a Society of Petroleum Engineers conference in Pittsburgh in mid-October.

C. Michael Ming, president, Research Partnership to Secure Energy for America (RPSEA), noted the importance of basic research into unconventional gas recovery technology. Partly due to such research, which is under constant threat of reduced federal and other funding, the US has more gas reserves today than when former US President Jimmy Carter made his "moral equivalent of war" (meow) speech in the midst of the late 1970s energy crisis, Ming told the conference.

World gas studyHolditch's students, who compared conventional and unconventional gas statistics from eight US basins, plan to expand the study to 25 basins.
The information covered petroleum systems descriptions and other public data on the San Juan, Green River, Powder River, Uinta-Piceance, Black Warrior, Wind River, and Illinois basins. Data came from the National Petroleum Council, US Geological Survey, Energy Information Administration, Gas Research-Gas Technology Institute, Potential Gas Committee, and other sources.

When looking at a given target basin or formation anywhere in the world, we can find the analogous basin or formation in the US and glean from published case histories that abound in the literature what amount to the best practices for recovery of unconventional gas, Holditch said.

The system, still a work in progress, is advisory in nature and not an expert system, he cautioned. Unconventional oil reservoirs have not yet been considered.
Part of the current study, for example, lists US basins and ranks world basins by most analogous, second most analogous, and so on. The software would eventually help operating companies, service companies, and others to select a tight gas sand fracturing fluid, for instance, using defaults and best practices from similar US reservoirs as a starting point, Holditch said.

Need for research
Carter delivered the "meow" speech about the same time that Houston wildcatter George Mitchell "decided to take a stab" at producing gas from the Barnett shale, Ming recalled.

Noting that the drilling, completion, and stimulation procedures for each shale must be uniquely decoded, Ming said that operators are still improving Barnett shale gas recovery factors. Some of the improvement can be laid to iterative actions, but with concentrated research, the process might become more predictive, he postulated.

The positive contributions from projects such as DeepStar, Norway's DEMO2000, and Brazil's deepwater program demonstrate that what begins as pure research can be driven toward field demonstrations and commercialization, Ming said.

RPSEA, he noted, is shepherding projects on emerging shales in Alabama, the Barnett shale, treatment and management of produced and all other waters, advanced hydraulic fracturing technology, how gas migrates to fill unconventional reservoirs, and how to increase the area of reservoir contact in horizontal wells, among other projects.
To access this article, go to:http://www.ogj.com/articles/article_display.cfm?ARTICLE_ID=341206&p=7

Horizontal Drilling Animation

$4,000 for a seven minute view of horizontal drilling.......get it now for free. This is very well done.....(no pun intended). Click on the following link. Peter

http://www.geoart.com/animations/horizontal_sandstone_drilling.php

In The Early Days........

Horizontal drilling once was guesswork, especially from the geologist's perspective. The drillers might know how deep they were, and what direction they were drilling, but there was no way they could know what stratigraphic layer, and thus "pay zone" they were in. When spending millions of drilling dollars, "guess-work" is not enough. In comes what I am saying, geologic interpretation of horizontally drilled wells. Following is an article from the "early days".....we've come a long way since then. Now we can drill through layers of rock like those imaged in the seismic line shown below, and stay within the "blue" layer. Could you?
Peter

Two Geologists = Three Interpretations
Geosteering: Like Landing In Fog
By DAVID BROWN EXPLORER Correspondent (source) December, 2000

(The following is a tongue-in-cheek description of the difficulties of horizontal drilling. Now we have much more control. Peter)

Ed Stockhausen knows the strains, the pains and the gains that come from guiding a drill bit through a zone with geosteering.
"First there is the 'landing the well in the reservoir,' then there is the drilling of the lateral section," he said. "It's kind of like landing a plane on a runway in the fog, when the runway is moving up and down."
Officially, Stockhausen is a senior research scientist at the Drilling Technology Center of Chevron Petroleum Technology in Houston. More to the point, he serves as geosteering advisor for Chevron operating units worldwide.
He defines geosteering simply as "the use of real-time geological and directional data to help guide or place a well."
So where does the pain come in?
Try geosteering the bit on a 1,000-foot lateral, with a drill rate of 30 feet an hour, and you've been awake for 24 hours assessing continuous downhole information, with more than nine hours left to go.

Hello, coffee. Hello, mental overload.
Horizontal wells have become an important production tool in the Middle East, according to Walid Kholeif, operations geologist for Abu Dhabi Marine Operating Co. (ADMA-OPCO). The company is 60 percent owned by Abu Dhabi National Oil Co. (ADNOC) and 40 percent by minority partners, he said.
An internal survey brought out requests for information on well placement and steering, Kholeif recalled.
"The feedback was mainly directed toward horizontal well activity," he said, "and, also, directed toward the drilling techniques instead of the geology."

In response, AAPG helped arrange and sponsored the Abu Dhabi Geosteering Workshop, which was held in April. Kholeif coordinated the workshop and called it "perfect" for the company's needs.
"It was really practical information," he noted, "not just academic, or only a few papers you could get into."
Thinking in a Real (Time) Way
Geosteering involves "a different kind of thinking from what a geologist normally gets into," Stockhausen said. "We're used to taking weeks and months to think about the data and adjust our maps."
In geosteering, the geologist gets real-time data from downhole tools and gives the driller feedback to direct the bit.
"You're trying to predict the geology just ahead of the bit, particularly the dip of the beds," Stockhausen said. "You're making decisions on the spot, continuously, and you do the best you can.
"Many times you get lost in these wells," he continued. "You don't know if you're going out the top of the zone, or the bottom of the zone. You're looking for a marker bed."
Some horizontal laterals may drill at a rate of only 15 feet per hour, and Stockhausen described those wells as "cruel, because you're getting data so slowly, there is too much time for second-guessing yourself."

Other 1,500-2,000-foot laterals may drill in less than a day.
"Those wells are actually a blessing," he explained, "because you can say, 'OK, this is going to take 15 hours and I can stay awake, I will make my decisions and it will be over soon.'"
Is it possible to use two geologists taking turns on a longer project? Sure, Stockhausen said - but then you run into the traditional problem: Whenever you have two geologists, you get three interpretations.

Justifiable Costs?
In Abu Dhabi, according to Kholeif, geosteering helps to place wells - or "land" wells - in the reservoir layer to facilitate water or gas injection. It's a useful tool in efforts to maintain reservoir pressure.
"We have not yet done this for exploration," he said. "It's strictly for production."
The typical geosteering project begins with well planning, and in particular a drilling model that includes geology, resistivity and other important reservoir elements, according to Kholeif. And a good project places the geologist at the drill site "to direct the well to the best reservoir quality.
"There should be some experience in the field," Kholeif said. "If you have a geologist who is not experienced in the region, it would be a little difficult for him to begin.
"The key to the success of geosteering is really in the preplanning stage. You're trying to plan around your uncertainty."

Usually, Stockhausen said, "your targets are smaller than the accuracy of your maps.
"You try to use marker zones that are above the beds you're trying to get into," he continued. "You plan the design around those marker beds and make sure you enter them at the angle you want. This allows you to then continue forward to softly land the well in the reservoir.
"Getting too far ahead or behind on the plan leads to lost footage in the lateral section and lost reserves."

Stockhausen jokingly added that "you aren't allowed to have any of those unanticipated (geologic) faults along the well path. Little 10-foot faults can throw everything out the door."
He admits that geosteering initially earned a bad name for being too expensive - but, he added, geosteering actually involves a comparison of costs and benefits.
For instance, tools that provide inclinational measurement near the bit cost more to use than tools with these instruments further back, Stockhausen explained. The difference may be a three-foot drilling window from near-bit readings compared to a 10-foot window from other tools.

If the smaller drilling window leads to more accurate well placement, and the difference is capturing 100,000 more barrels of oil, the cost of near-bit information, he said, may be well justified.

Familiar Sights
Displays of downhole information in geosteering would be familiar to most geologists. Data is sent uphole and displayed in the normal way, said Ted Bornemann, principal geologist for Schlumberger's Center for Advanced Formation Evaluation in Houston - better known as the "SCAFE" (and pronounced as "S-Café").
"The commonly used tools are the gamma ray tools and the resistivity tools," he said. "Some new technology that's emerging now is the use of image data while drilling - real-time imaging."
Those imaging tools "show very graphically whether we are drilling up or down, or staying within the layer of the reservoir," said Bornemann, who specializes in forward modeling in drilling.
Imaging tools are located some 35 feet behind the bit, he said, while gamma ray and resistivity tools can be located right behind the bit. In every case, data is transmitted uphole by mud telemetry - pulses sent through drilling mud.
"That's why the data transmission is somewhat limited," he said. "It's not the bandwidth and the signal type you have in a wire, like you can get with wireline tools."
What might not be familiar to geologists are the downhole readings from a lateral well. Resistivity anisotropy produces anomously high resistivity readings different from those seen in a vertical well, according to Bornemann.
"In essence, the resistivity measurements look a little unusual," he said.
Where Am I?

Geologists who want to be successful in geosteering need to learn a foreign language:
Drilling.

"Drillers want target information," Stockhausen said. "This is one of the biggest challenges, how to communicate to the driller.
"I like to have the geologist on the rig site, because they can talk to the driller in person and negotiate."
To help guide the well, a geologist should know how the driller targets the hole and what information is needed to make adjustments. It's also important to understand the basics of directional drilling, Stockhausen said. Ask a driller if it's possible to lower the hole 10 feet in the next 10 feet of forward drilling, and the always-polite driller will respond:
"I don't believe so, sir."
Or words to that effect.
"Targets in horizontal wells tend to be lines - actually, moving lines - and well plans need to be flexible," he said.
"As we get information on the geology, we may have to admit that our line's in the wrong place and ask if we can please move it. But if you make too many kinks in the well you're going to stick the drill pipe," Stockhausen said.
And the geologist has to exercise restraint in making adjustments as downhole geology and measurement differ from the predrill model.

It's easy to oversteer a hole.
"There's always a constant issue of losing the well," Stockhausen said. "I try to preplan my decision points around a few key marker beds: These decision points should be communicated to the entire drilling team prior to drilling.
"When these beds are encountered while drilling, then it is time to make a decision - and then I'm going to talk to the driller about how to adjust the well path," he said.
"Preplanning key geosteering decision points allows wells to be drilled without as much alarm."
"Also, you've got to do everything in a very site-specific way," he continued. "That's one of my favorite terms, site-specific. You can't use the same geosteering techniques for every well in the world."

"Drilling a well is not like playing with a joystick on the computer," Bornemann noted. "There are a lot of restrictions on drilling a well."
In geosteering, the geologist must "work out the geology as detailed as possible along the planned azimuth of the well," he said, while knowing the characteristics of each layer above and below the hole.
"The real trick in geosteering is to know where you are geologically," Bornemann continued. "Through this whole process of landing the well, we will encounter a number of these formation tops. If we can recognize this marker on this new well we are drilling, we can say, 'Now we know where we are.'

"That does not mean we know in absolute depth from the surface where we are, but we know that 15 feet below this marker we have identified is our target zone."
Awareness and Accuracy
Even with good knowledge and reliable measurements, location can be difficult to pin down. That's when the driller is waiting for instructions and instead of breaking out in a smile, the geologist breaks out in a sweat.
"Everyone on the rig knows if the geologist is lost," Bornemann said.
"The people who tried to do horizontal well drilling without geosteering techniques drilled to a line drawn on a sheet of paper. You'd give a piece of paper to a driller and say, 'Drill these XYZ coordinates' without putting any geology on there," Stockhausen said.
The problem with that approach, Bornemann noted, is that a good driller could drill a perfect hole that matched the coordinates exactly, and the well might not be in the reservoir. There's too much uncertainty in mapping.

Stockhausen recalled his frustration the first time he tried geosteering, not having the tools and techniques he needed. He said Chevron recognized the need for a company-wide approach to geosteering instruction.
"In team environments, geologists become severely isolated from other geologists. We were all making the same kind of mistakes," he said. "That's when we began to see that there was some teaching needed."
Because of their reputations and experience, Stockhausen and Bornemann were asked to conduct the Abu Dhabi Geosteering Workshop. One challenge in Abu Dhabi, Stockhausen said, is to keep a directionally drilled hole in a thin, high-porosity zone for as much as 2,000 or 3,000 feet.

"You can imagine trying to stay in a 10-foot zone for 2,000-3,000 feet, how accurate you have to be. Some of this sounds somewhat impossible, but the zone helps you. A lot of times, the zone you're drilling in is the softest zone, and the bit is very content to stay there," he said.
Bornemann said he might have changed a few things about the workshop held in April, but not very much. He rated it highly successful for a first-of-its-kind effort.

"One of the biggest things was that everybody in the class came away with the feeling that he was well aware of the problematics of geosteering," he said, "and that is, principally, that you have to be aware of the uncertainties involved and what you can do to minimize them, thus drilling a successful horizontal well."

What Is The Barnett Shale Gas Play In Texas?

The Barnett Shale Gas Play in north Texas is the real deal. It is producing a LOT of natural gas and is a true economic "bonanza" for the region. It would not be possible without the new technology of horizontal drilling and the ability of geologists and engineers to interpret the data coming from these directionally drilled wells. Of course other advances in drilling technology and completion techniques play an extremely important role as well.

Do we in America want to become energy independent? Do we want to create jobs and keep our money here in America? Of course we do. Then it seems obvious we should encourage more drilling and production of clean burning natural gas from formations like the Barnett Shale. More on this idea will follow in future posts.
Peter


The Barnett Shale Gas Boom
Igniting a Hunt for Unconventional Natural Gas Resources

Marc Airhart, Jackson School of Geosciences, The University of Texas at Austin

The global hunt for unconventional gas reserves recently turned to an unlikely spot—a patch of north central Texas that already seemed tapped out after 50 years of intense oil and gas drilling.
Technology, economics and one man’s persistence transformed the Barnett Shale formation of the Fort Worth Basin into a booming new frontier.

(Map showing the approximate location of the Barnett Shale Gas Play in north Texas.)


Barnett Shale gas is the largest play in the State of Texas. © iStockphoto / Jim Parkin
In less than a decade, the Barnett Shale play has become the largest natural gas play in the state of Texas and, as new wells sprout like bluebonnets across the Fort Worth region, it might soon become the largest in the nation. Click to enlarge.

As conventional petroleum reserves dwindle in the U.S., public pressure mounts to reduce the country’s dependence on foreign energy, and the price of oil and gas rises, energy companies are setting their sights on “unconventional” domestic sources. These include oil sands, coal beds and shales.

In less than a decade, the Barnett Shale play has become the largest natural gas play in the state of Texas and, as new wells sprout like bluebonnets across the Fort Worth region, it might soon become the largest in the nation.

“This play already covers parts of 15 or more counties,” says Eric Potter, associate director of the Bureau of Economic Geology at the University of Texas at Austin. “It compares favorably with the biggest of the old oil booms of the early 20th century.”

Of course this boom is different. The concrete-like shale gives up its gas grudgingly. So individual wells tend to be smaller and more expensive to operate.
“The East Texas gushers would win out hands down,” says Potter. “But there are so many [Barnett] wells that even though they are modest, the total output is going to be huge.“
This play is also different because much of the untapped gas lies under the highly populated Fort Worth metropolitan area. Oil and gas companies are finding new challenges drilling in an urban setting.

Now, some experts are wondering if the boom can go global. The search is on for similar shale formations around the world, including the Fayetteville Shale in Arkansas.

Going to the Source
The fact that there is a Barnett boom at all reflects a tectonic shift in thinking. In the past, drillers bypassed the source rock that generated the oil and gas and focused on the reservoir rock, where the resources were easier to extract. Typically, oil or gas exits from the source rock and migrates to places where it is trapped. And those traps—conventional fields—typically do not cover a large area.

“There would be a field here and then a lot of blank space and then a few miles over there would be another field,” says Potter. “But this kind of play, it just covers county after county. You’re looking at thousands and thousands of wells covering the land.”
With new technologies for coaxing gas out of shales, drillers see the Barnett as both source and reservoir. One such technology is artificial fracturing—in which operators pump water and sand down a well to create fractures that liberate more gas from the rock.

Potter and his colleagues at the Bureau are analyzing the properties of shales across the state. Ultimately, they hope to apply their work to similar rock formations anywhere in the world.
“Now any kind of mudrock or shale that’s black, organic rich, reasonably thick, and reasonably deep we’re interested in,” says Potter. “The question is, all shales are not alike, so what makes a shale prospective as opposed to one that is not prospective? We don’t really know that yet.”

Play Money
Before he died in 2003, oilman and philanthropist John Jackson donated to The University of Texas at Austin royalty interests in roughly a thousand wells in the Fort Worth Basin, part of the bequest that led to the formation of the Jackson School of Geosciences. These wells were producing oil and gas from the younger Bend Conglomerate formation just above the Barnett.
The Bend Conglomerate was formed during the Pennsylvanian age, meaning it was laid down about 290 to 320 million years ago. The Barnett Shale, a marine basinal deposit of middle to late Mississippian age, was laid down about 320 to 360 million years ago.

Could the same wells produce significant amounts of gas from the older, deeper Barnett shale? Potter and his colleagues at the Bureau helped the University assess the long-term potential of the University’s royalty interests.

“The short answer is that we think that most of that acreage has quite good potential in the Barnett,” says Potter. “Eight of the top ten Jackson School royalty wells are producing from the Barnett Shale. We are forecasting that most of these holdings will produce from the Barnett.”
The University receives on average about two percent of the gross revenue from wells it holds royalty interests on. That money is being used to build one of the world’s premier geosciences programs at the new Jackson School. Because the money goes into general funds, it supports all of the activities of the school, including dean Eric Barron’s priorities: to create the world’s most student-centered earth science program, to attract and retain the best research talent, to increase the breadth and depth of the faculty and research community and to establish the “fabric of a great school.”

Researchers at the Bureau are providing technical analysis to help stimulate additional drilling and production in Wise County, where most of the University’s royalty interests are located. Emphasis so far has been on mapping the basic stratigraphic and structural framework, tracking successful drilling in the less developed southern part of the play, mapping similar conditions in Wise County, and remapping the thermal maturity of the formation. The maturity seems to relate directly to the gas to oil ratio, one of the key factors controlling gas flow rates.

According to Potter, the 5,500 wells currently pumping gas in the Barnett Shale play will ultimately generate on the order of $35 billion for their owners. As those companies pay taxes and wages, and as their employees and contractors in turn spend their money, there is an economic ripple effect, creating an overall value of about $100 billion to the Texas economy.

Graph showing yearly production of gas from the Barnett Shale in the Fort Worth Basin in BCF,

(Billion Cubic Feet).

Of course, that is only counting current wells. Potter predicts that if gas prices stay relatively high, tens of thousands of new wells will be drilled in the coming decades.

“It’s a ubiquitous reservoir,” says Larry Brogdon, partner and chief geologist for Ft. Worth based Four Sevens Oil Company. “It’s everywhere. You can not drill a well without hitting the Barnett, and the gas is always there. The question is can you get it out or not.“
So far, operators have extracted 2 trillion cubic feet of gas from the Barnett Shale play. At about 1.5 billion cubic feet a day, that’s about 2 percent of the daily natural gas consumption of the U.S.
“When you can go from nothing to the second largest producing gas field in the country in a matter of just a few years, that makes a statement,” says Rich Pollastro, a geologist with the U.S. Geological Survey in Lakewood, Colorado. “That’s huge. And it could potentially become the largest producing field in the country. That was a real awakening for the country and now because of its success, industry and nations are looking at it worldwide.”

Map showing the extent of the Barnett Shale in Texas (shown in orange).

The Next Barnett
In the summer of 2004, Southwestern Energy announced that the Fayetteville Shale formation in the Arkoma Basin had many of the same characteristics that made the Barnett Shale formation so desirable for gas production. Before the announcement, the company had quietly acquired mineral leases on nearly a half million acres of land.

The announcement set off another gas boom. Oil and gas operators familiar with the Barnett Shale rushed to Arkansas to get in on the action.
“The analog would be like a 19th century gold rush,” says Ed Ratchford, geology supervisor for the Arkansas Geological Commission in Little Rock. “Everyone stakes a claim. You don’t say this place is going to be better than this place. You don’t have time. People were leasing thousands of acres a day.”

Ratchford and his team maintain a well log library, a collection of well cuttings and cores from oil and gas wells across Arkansas. They used these to conduct geochemical tests on samples from the Fayetteville Shale and produce a regional picture of where good gas prospects were likely to be.

“We had companies all over us waiting for us to get this stuff done,” says Ratchford. “They were sitting out in the parking lot before we opened up. We were the only ones that had this information. It was critical for helping the operators know where to lease.”
In the excitement, many companies took a gamble on mineral leases.
“We had a lot of companies that had leased before the report came out,” says Ratchford. “Then they had a big golf ball in their throats saying, ‘I wish I hadn’t leased here.’ That’s the risk you run when you lease big tracts of land in a boom without having the luxury of doing the science first.”

“Some of those companies are going to make a lot of money,” notes Ratchford, “some are going to be doing tax write offs. That’s the nature of exploration. In a situation like this, where there’s a frenzy, there are going to be winners and losers.“
It’s too early to tell how much gas will ultimately be recoverable from the Fayetteville Shale. Southwestern Energy, still the largest lease holder in the play, estimates that they will recover 17 trillion cubic feet of gas.

The future looks good for the Fayetteville play. Ratchford expects the number of wells producing in the area to rise from the current 80 to a couple hundred and that gas will be extracted for at least 15 or 20 years.

He also notes that oilfield services provider Schlumberger has recently built a 30,000 square foot facility in Conway, Arkansas and will employ approximately 100 employees at that facility. “They would not do this if they didn’t believe this would be a long term venture,” says Ratchford.

Other areas that have generated interest for possible large shale gas plays are the Caney and Woodford formations in Oklahoma, the Floyd formation in the Black Warrior Basin of northwest Alabama, and the Barnett and Woodford formations in the Permian Basin of Texas.
It remains to be seen if the rising star of the Barnett Shale play will be eclipsed by other gas plays.

“The Barnett might be as good as it gets,” says Pollastro. “No one knows for sure.”
He produced the U.S. Geological Survey’s assessment of the Fort Worth Barnett shale play in 2003. At the time, he estimated that it held a remaining volume of 26 trillion cubic feet of recoverable unconventional gas. Now he’s evaluating the Barnett and Woodford formations in the Permian Basin, where drillers have experienced mixed results.

“It’s a different animal,” he says. “The Barnett in the Delaware Basin part of the Permian Basin is deeper and is more clay rich, so at present it’s not working like everybody thought it would. It’s not as rich in organic material as the Fort Worth Basin. I think there’s good potential, but I think there will be a steep learning curve.”

For more information about the Jackson School contact J.B. Bird at jbird@jsg.utexas.edu, 512-232-9623 - or visit their website.

Horizontal Drilling: A Major Success

As long as geologists have been drilling holes in the ground they've known that organic rich shales often contain oil and gas. They recognized this as they drilled through these common layers of rock. They often tried to produce this oil and gas, but because shale, by its very nature is "tight", meaning it normally has extremely low porosity and permeability, they were unsuccessful. Until recently, no geologist did more than dream of producing much oil and gas from shales. They were only considered source rocks for the oil and gas found in other formations.

But George Mitchell was tenacious and persistent, as will be shown in the following article. With time, effort and money, he found a way to make the Barnett Shale in Texas pay off.
Peter


The Father of the Barnett Natural Gas Field: George Mitchell
by Marc Airhart, Jackson School of Geosciences, The University of Texas at Austin

A unique set of factors converged to kick off the Barnett boom. New technologies such as artificial fracturing and horizontal drilling made it possible to extract large amounts of gas from shales. The relatively high price of gas in recent years made it economically viable.
Yet according to Eric Potter, neither of these would have mattered without one critical element:
“It wasn’t high tech. It was persistence and experimentation on the part of one company that got this boom going.”

Mitchell Energy had produced gas from a shallower formation, the same formation that John Jackson had discovered in the 1950s. That production was waning.
“They began looking around for what could be done in the same area,” says Potter. “They had always noticed that when you drilled through the Barnett, you would get a gas show. But everyone thought you wouldn’t get much gas.”

Even though shale may have a lot of pores with the ability to store gas, it is not very permeable. In other words, it does not have many connections between the pores and so trapped oil and gas can not flow easily.

“Mitchell Energy sunk a lot of money over a long period into learning how to stimulate the rock so it would flow,” says Potter. Their first attempts were expensive “massive hydraulic frac jobs.” They would pump a very large volume of fluid and sand down a well bore to crack the rock and give it more permeability. At first, they got the gas flowing, but the methods and materials were expensive. So they wondered if they could pump less fluid and get the same effect.

“They arrived at something called a light sand frac,” says Potter. “Suddenly it was economical and at the same time—in the mid-1990s—the price of gas was rising. By the late 1990s, they had perfected the technique in vertical wells and started applying it to several hundred wells. That’s when it came to the attention of industry.”

Potter first heard about these early successes from a Mitchell employee in 1996.
“I didn’t think it would have the kind of impact it did,” he says. “I wasn’t the only one. Most people in industry were surprised and had difficulty adjusting to the notion that shale could produce in commercial amounts over such a wide area. There were only a few companies that appreciated the value of hydraulic fracture technology applied on such a large scale.”

When thermally-mature organic-rich mudstone is drilled into, the pressure drops and gas is released by a process called desorption. Early estimates of how much gas would be given up by the Barnett Shale turned out to be far too low. The experiments were run again and it was realized that this shale would give up much more gas than was previously thought.
“Then it was realized, oh, if you scale that up to the whole area and then to the whole county and up to the whole Basin, the amounts of gas are really quite prodigious,” says Potter. “People became aware of that in 2002 and 2003 and that really got the ball rolling.”

Mitchell Energy already had critical infrastructure in place to process and transport gas. So they could quickly and economically take advantage of the discovery.
“It took George Mitchell 18 years to make it work,” notes Larry Brogdon, partner and chief geologist for Four Sevens Oil Company. “He is the father of the Barnett Shale. He was tenacious. He started in 1981 and it really didn’t take off until 1999. And even then, it took a long time to develop it.”

For more information about the Jackson School contact J.B. Bird at jbird@jsg.utexas.edu, 512-232-9623 - or visit their website.

Why Horizontal Drilling?

There are many reasons why horizontal, or directional wells are valuable and almost indispensable to modern oil and gas production. The following simplified article explains just a few. The BIG question, from a geologist's point of view is "HOW does a person at the surface know where the drill bit is and where it is going?" Remember, the drill bit and hole can be up to tens of thousands of feet below the surface of the Earth and thousands of feet away from the surface location. In order to "steer" the well you must know where it is. In order to know what layers of rock the well has drilled through a geologist must be able to recognize them.

This is where the art and science of interpretation comes to play and I'll attempt to answer these questions in future posts.
Peter


Horizontal drilling (source)

We talk about "pools" of oil, but in fact the stuff exists between the grains of porous rock like sandstone. Oil can travel through rock, but so slowly that it would probably lose a race with a whip-tailed paramecium.
So if you're interested in oil, you gotta make house calls. Translated: You gotta drill right into the reservoir. Not only can it be a tiny target, but even if you hit a bulls-eye, the well may be unproductive. Say a vertical drill pierces 5,000 feet of rock into an oil reservoir that's 20 feet thick. Because oil moves slowly, the 20-foot exposure would not tap much oil.
Over time, of course, more oil would seep toward the well, Bergt says. "If you could wait one million years for nature to refill it, that would be great." But drillers can't wait that long, and "In the old days, you'd move 200 feet and drill another well."

Once upon a time, drillers extracted oil with this Swiss cheese routine; new techniques reduce the need for wells. (Image courtesy of the United States Department of Energy.)

Do the math.

In a big field, thatsa lotta holes. Expensive holes.
With horizontal drilling, the entire picture changes, Bergt says. "Instead of drilling 20 wells, you'd drill two or three for the same recovery." On land, the technique also reduces the "footprint," the area damaged by drilling operations. At sea, it allows drilling many wells from a single platform.
Bent pipe solution? Because the pipe that drives oil drills is surprisingly flexible, a horizontal well can snake around to reach isolated pockets or follow a reservoir that meanders across the terrain.
Horizontal drilling has evolved over the past 25 years, and even though it remains more expensive than vertical drilling, greater productivity led to rapid acceptance. Between 3,000 and 4,000 wells are drilled annually with the technology. The record hole is a long-haul monster that wanders almost 7 miles, on the coast of southern England in the Wytch Farm oil field.

This roller cone drill bit was adapted from one used by 19th -century dentist (NOT). Use it to cut hard and/or abrasive rock.
Courtesy University of California-Berkeley petroleum engineering program.

Coil tubing

Traditionally, oil bits were driven by 30-foot sections of steel pipe. Pulling a bit up for sharpening involved hours or days of yanking pipe out of the ground and unscrewing it. In the past five years, drillers have come up with an alternative -- coil tubing.
Packed in giant reels holding 4,000 feet of tubing, the stuff is simply unreeled and lowered into the hole. Instead of rotating the tubing to spin the bit, high pressure drilling mud is sent, as usual, through the tubing. At the other end, however, is a hydraulic motor that rotates in response to mud pressure.

Peter Meenan says coil tubing also lends itself to scavenger operations -- tapping pockets of petroleum that seismic techniques show are near to existing wells. Meenan, who directs the Oil and Gas Institute at the University of Aberdeen, Scotland, says coil-tubing drilling, combined with steerable drill bits, may be used when a new pocket of hydrocarbons is discovered, say, 1,000 feet from a deep well. Rather than drill from the surface, it's possible to start drilling part-way down and veer off to reach the new deposit.

Welcome To GeoPete's View

Dedicated to the prospector and explorer in all of us. Never say die. Never give up.

Welcome to my blog about the topic of horizontal drilling as it relates to oil and gas exploration. Actually, the term "horizontal drilling" is a bit of a misnomer. In reality, what we are dealing with is controlled directional drilling. The object is to create a well bore in a productive oil or gas pay zone for as long a distance as is possible. This requires navigating or steering the well as it is being drilled. Increased production rates, volumes, and profitability are the ultimate goals.

Since oil and gas is almost always found in sedimentary rocks deposited in layers, the trick is to keep the well in one or more of these preferred layers. These layers of rock can vary considerably in thickness, structure, and many other properties. This is why geological knowledge and experience is so important. However, the geologist can not work alone. Engineers and others are a vital part of the process and we must all work together.

I am an independent, consulting geologist, trained and experienced in exploration and interpretation, so my input here will be from that perspective. However, I will be posting what I consider relevant articles from geologists, engineers, geophysicists and others. I hope to generate input and discussion from those interested in this relatively new technology. Drilling, interpreting and completing these horizontal wells is expensive and challenging. It requires the coordinated effort of a team of experts.

Please add your comments, experience, and questions. If I don't have the answers, I'm sure I can find someone who does. Sharing our knowledge is the name of the game.