EXPLORER Correspondent

Infrastructure Key to Gas Play

Barnett Shale Living Up to Potential

Photos courtesy of Devon Energy
Things are looking up in the Barnett Shale north of Fort Worth, Texas.

There's a giant gas field currently being explored that has a trillion cubic feet of natural gas every seven square miles.

It's got to be in the Caspian Sea or the deepwater Gulf of Mexico, right?

In fact, just north of Fort Worth, Texas, not far from some of the oldest production in the oil patch.

Explorers missed this giant field for 100 years -- and perhaps with good reason. This huge gas resource was hiding in the source rock for much of the shallower production in the Fort Worth Basin, and the Barnett Shale doesn't give up its secrets easily.

Just ask scientists with Mitchell Energy who worked for almost 20 years making the Barnett play an economic proposition.

But their work is paying off. Today the Barnett Shale is living up to its potential and opportunities to expand the play abound -- a good development, because scores of government and industry studies indicate that unconventional natural gas resources are vital to United States' energy future.

In that light alone, enormous shale gas plays like the Barnett are an important step toward exploiting that resource.

Over 1,200 wells have been drilled in the Barnett and another 400 wells are being drilled or completed, awaiting permits or shut in waiting for pipeline connections, according to Larry Brogdon, exploration manager for Four Sevens Oil Co.

"In January 2000 there were 566 completions in the Barnett, and since that time another 750 wells have been drilled," he said.

Currently there are 38 rigs running in the area.

"To say the play has exploded," he added, "would be a major understatement."

First Steps

Roughnecks conduct drilling operations on a natural gas well in the Barnett Shale.

This story of the Barnett Shale begins in 1981, when Mitchell Energy (acquired by Devon in 2001) drilled its first well to test the formation.

Mitchell had produced from shallower zones in the area, but that production was beginning to decline and the firm was looking for new reserves to feed its extensive infrastructure in the Fort Worth Basin.

"There were tremendous gas shows in a mud log of the Barnett," said Dan Steward, a consulting geologist with Republic Energy, Dallas -- the second most active company in the play -- and former vice president of exploration with Mitchell Energy, "so we perforated the zone and did a small frac job. We got some gas and over time went back into the well with a larger frac and got a little more gas.

"The well wasn't economic," he said, "but it did focus attention on the Barnett."

Mitchell also was drilling development wells in the shallower Boonsville gas field in Wise, Jack and Parker counties, and decided to also deepen some of those wells to the Barnett. The incremental costs were not excessive and the program provided the opportunity to learn more about the geology and reservoir characteristics of the Barnett Shale, he said.

"We wanted to get a feel for stratigraphy, the maturity of the rock, the structural complexity -- what made one Barnett well better than another," Steward said. "We didn't have a well that would be considered commercial from the Barnett until we had deepened about 40 wells."

The wells were deepened to an average of 7,500 feet to the Barnett. The older, shallower production was at 5,500 to 6,000 feet.

The company took core and ran mud logs on the zone to analyze the gas in place, and looked at the area's structural conditions to determine whether or not to drill for the Barnett around faults.

"Initially we felt it would be best to drill for this tight gas reservoir around faults," he said, "because at that time the Chalk plays in Texas were most productive around naturally faulted areas."

The Value Chain

In 1986 Mitchell cored the entire Lower Barnett section and did an extensive analysis to study the porosity, permeability, organic content and fracture orientation.

This study, along with results from a well drilled in a tectonic fault zone, proved natural fracturing was not a benefit in the Barnett.

"Core showed that while there was extensive fracturing in the area, they were completely sealed by calcium carbonate," Steward said. "These faults were likely the main avenue for migration of Barnett gas into the overlying Atoka and Strawn sections, and water migrating with the gas caused cementation of the natural fractures."

After years of trial and error in the Barnett, Mitchell began employing large gel fracs on the wells.

"As we got the frac size up to a theoretical 1,500 feet in half-length we started making wells that came on at decent rates, dropped fairly rapidly and then stabilized," Steward said. "We were feeling better and better -- we could expect on a routine basis about one billion cubic feet of gas from our core area."

While the wells were finally producing at substantial rates, the play was still economically shaky because the large gel fracs were extremely expensive.

In fact Mitchell was likely the only company that could have made the Barnett economic at that time because of its infrastructure in the area.

"Well costs were close to $1 million," said Kent Bowker, exploration manager with Star of Texas Energy Services and a former geologist with Mitchell Energy. "This play definitely would not have been commercial without the value chain Mitchell had with its gas gathering lines and large gas processing plant in the basin."

Adding New Data

Mitchell continued tweaking the Barnett Shale play all through the 1990s -- and then in the late 1990s two things occurred that revolutionized the play, Bowker said.

Completion engineers at the firm took a chance and started experimenting with water fracs that proved successful.

At the same time Mitchell scientists, using techniques developed by the Gas Technology Institute, did a new core study with state-of-the-art technology that proved the gas in place figures were actually four times more than previously believed.

"For years we thought we were getting about 30 percent of the gas out, which is quite good from a tight shale," Bowker said, "but this new study proved we were actually only getting about 7 percent and that's terrible."

Steward explained that in 1997 Mitchell had begun studying the potential of slick water fracs for the Barnett.

"This technique could reduce stimulation costs by 70 percent," he said. "The slick water fracs were comparable in performance to the gel fracs -- and over time, as we perfected the water fracs, stabilized gas flows generally met or exceeded the rates we achieved with gel fracs."

Another benefit of the new water frac program was the opportunity to target the Upper Barnett.

"We knew there was gas in the Upper Barnett, but due to the costs of the gel fracs we couldn't go after it," he added. "With the slick water fracs we could exploit the Upper Barnett cost effectively.

"The Upper Barnett adds on average a quarter of a billion cubic feet of gas, which is clearly commercial for either a re-completion or as an added stage of completion in new wells."

Fracture Focus

Mitchell, now armed with the successful water fracing program and this new information, embarked on a drilling program that included downspacing, re-fracing old wells and testing the Upper Barnett. Steward said the re-fracs were extremely economic, often boosting production to its original levels and starting the decline curve all over again.

Based on Mitchell's studies, the average gas in place in the Barnett Shale is 160 billion cubic feet of gas per square mile. The Barnett is the largest producing gas field in Texas, according to Bowker, and the reservoir covers 15 counties in North Texas.

The commercially productive area covers 60 square miles in Wise, Denton and Tarrant counties, and Devon Energy and others are working to extend the play's limits.

According to Bowker, the Mississippian-age Barnett Shale is a black, organic rich siliceous zone that was deposited in the quiet waters of a back-arc basin just before the formation of the Ouchita Mountains. The Barnett hydrocarbon system is one of the 10 richest in the world, due to the massive organic matter deposited in this setting.

The main tectonic elements dictating the Barnett play are the Ouchita Mountains to the east, the Munster Arch to the northeast and the Bend Arch, which is an old structural high running north to south that defines the western margin of the Fort Worth Basin.

Barnett production is controlled by the formation's thickness, which ranges from 50 feet on the Bend Arch to close to 1,000 feet out in front of the Munster Arch in the basin's center. In the most productive areas the Lower Barnett is about 300 feet thick and the Upper Barnett is around 150 feet thick.

"Finding the optimum fracture techniques was critical to the Barnett play since average permeability is in the nano-darcies and porosity averages between 5 and 6 percent," Bowker said. "Matrix permeability is nil, but we hope for permeability along the fractures."

The typical fracture stimulation today consists of a million gallons of water and 50,000 pounds of sand to create a theoretical zone of fracturing that is about 1,500 feet long in both directions, for a total length of 3,000 feet.

Average cumulative production from the initial fracture stimulation is 1.25 billion cubic feet of gas per well. The wells initially produce for about one million cubic feet of gas per day but experience a 50 percent decline in the first year. Then the wells stabilize and produce for an average 20 years, with expected life in excess of 30 years.

Re-fracing a well after five years or so of production can add another three quarters of a billion cubic feet of gas to a well's overall production.

"The frac jobs run about $100,000 to $150,000 and the total average drilling and completion costs run $600,000 to $750,000," Bowker said. "With those kinds of costs and reserve figures Devon is pretty much printing money in the Fort Worth Basin."

In fact, the Barnett Shale was the key asset in the acquisition of Mitchell, according to Mark Whitley, production operations manager of the Fort Worth Basin for Devon Energy.

"Devon looked at Mitchell two years ago, and when they took another look last year and saw how dramatically Barnett Shale production had increased -- 55 percent on an annual basis -- the company was extremely attractive. The Barnett Shale is a vehicle for growth even for a company the size of Devon."

Devon currently produces about 400 million cubic feet of gas a day from the Barnett and has total proven reserves of 2.1 trillion cubic feet of gas, he said.

Pushing the Boundaries

Devon, Republic and other operators are continuing to push the boundaries of the play. Devon and Republic are planning to drill 300 and 84 Barnett wells, respectively, this year in the Newark East Field, the primary producing area, but the firms also have several additional programs designed to test potentially productive areas.

Four Sevens Oil Co. also has a stake in the Barnett and is testing its acreage in several locations.

"One of the crucial elements in this play is the barriers above and below the Barnett -- the secret is to contain the fracture stimulation within the Barnett," Brogdon said. "In the Newark East Field the Viola underlies the Barnett and acts as a barrier. However, as you go west the Viola pinches out and the Ellenburger underlies the Barnett, making it more difficult to contain the fractures in the shale."

Bowker said the problem in this area where the Ellenburger underlies the Barnett is that fractures can grow down into the Ellenburger, which is much more porous than the Viola and water bearing.

"All the fracture energy goes into the Ellenburger and you end up bringing in the ocean," he said. "A technology-driven effort must be made to determine how to contain the frac within the Barnett."

Over the years Mitchell did test the Barnett past the Viola pinchout, but in almost every case produced water from the Ellenburger. Whitley said Devon will kick off a program this year focusing on uncovering the optimum completion techniques for this area.

The firm has over 100,000 acres in the area.

"Back in 1997 we drilled two horizontal wells on this acreage and both made gas and no water, which is important, but the well costs were so high that the wells were uneconomic under any reasonable short term price of gas," Whitley said. "This year we will try another horizontal well with a different stimulation technique.

"We have to do better both on the cost side and the reserve side if horizontal drilling is to be successful."

Four Sevens and partner Denburry Resources have 22,000 acres in this area west of the Newark East Field. The companies have drilled six wells to date and small frac jobs were run on the first four wells.

Three of the four did make gas, according to Brogdon, but initial rates were economically marginal.

"We were afraid of communicating with the Ellenburger if we did too big a frac job," he said. "These smaller stimulation attempts didn't communicate with the Ellenburger, so on the last two wells we used typical Newark East type frac jobs. We are waiting on a pipeline connection for these two wells before we can see any production history.

"The jury is still out -- we don't yet know if our approach will work," he added. "However, if we can work out the science in this western extension it will increase the prospective Barnett area by three to four times."

Treading Water

To the north of the core Newark East play area Devon and other operators are trying to unravel the secrets of an area where the Viola is present but is wet in many places.

"We’ve drilled over 30 wells in this area, but water in the Viola has caused some difficulty in making economic wells," Whitley said. "All the operators are trading data in an effort to figure out what completion techniques will work best.

"This is a particularly important area for Devon," he continued, "because this is rich Barnett gas that would feed our Bridgeport processing plant, which is currently undergoing its third expansion in two years."

The company plans to do some additional science using formation microimaging tools, downhole sonic logs and other technologies to get a better idea of the fracture mechanics in the area.

"We also will try some different completion techniques," Whitley said. "For example, one method we will look at is intentionally fracturing the Viola to try and charge it up and then stimulate the Barnett on top without re-stimulating the Viola.

"We've had limited luck with this technique so far," he added, "but we will continue to refine our efforts."

Thinking Big

A third Barnett play area that is garnering attention is south of Fort Worth in Johnson County. Devon is particularly focused on this area because the firm has primary term leases that have to be drilled.

"We are by far the largest leaseholder in Johnson County with over 80,000 acres," Whitley said. "We know the Barnett is present, but again we are not sure what it will look like."

Devon plans to drill a three-well program in the most prospective area of our acreage later this year.

Despite the Barnett's tremendous success over the last several years, much work remains before the full extent of this huge natural gas resource will be tapped.

"Devon Energy knows more about the Barnett as a company than any firm, but what they know is the tip of the iceberg," Steward said. "There is no such thing as a Barnett expert yet -- we’ve just scratched the surface of what we have to know about the Barnett."

But there's an optimism that's unusual for an onshore domestic play.

"I personally believe the Barnett Shale will ultimately be larger from the standpoint of reserves than the Hugoton Field, which is currently considered the largest onshore natural gas field in the United States," he said.

Brogdon agreed.

"We will all be dead and folks will still be drilling Barnett wells," he said. "There are literally thousands of infill wells to be drilled in the core areas and operators will continue to push its limits. To me this is the perfect play. I've always dreamed of a play of moderate depth with no pressure problems, a high success ratio, simple operations and a location right out the back door."

Republic geologist Brad Curtis said that "in a play of this size where competition is fierce and technology is lacking, new information and clues to understanding the shale are uncovered every day. At a minimum, the play requires an integration of specialities within a company.

"The limited amount of exchange that existed in the early 1990s allowed Republic Energy to become the active player that it is today," he added.

"This 18- to 20-year overnight sensation is the kind of success story in the heart of the oil patch that makes you realize there are still tremendous opportunities for new reserves," Bowker said, "if you are willing to be persistent, push the scientific envelope and think outside the box."