Paleozoic Gas Shales

The rousing success of the Mississippian-aged Barnett Shale play in North Texas has reopened the industry's eyes to the potential locked in the organic-rich Paleozoic shales layered into other petroliferous basins.

Shale gas plays are continuous-type accumulations, covering immense areas. They are a well-known resource-William Hart drilled the first shale-gas discovery in 1821 in Fredonia, New York. A pipeline made from hollowed-out logs transported gas produced from the Devonian Dunkirk Shale to the town center, where it was burned to light the main street. Nonetheless, shale wells have traditionally been modest producers characterized by low production rates and long lives. And despite its lengthy history, shale gas has only managed to comprise a small percent of total U.S. gas production.

That's all changed in recent years.

Today's improvements in horizontal drilling and fracturing technologies are delivering some sterling rates from shale wells. Operators around the continent have taken notice of the prolific production flowing from the Barnett Shale, and are exporting techniques honed in that play to new basins. Naturally, each basin is geologically unique and requires a custom approach. Gas shales are both source and reservoir in one package, and they are far from uniform. Characteristics such as total organic contents (TOC), gas contents, thickness, depths and lithologies vary from basin to basin and also change within basins.

Additionally, gas shales can contain biogenic or thermogenic methane, and their thermal maturities can fall along a broad continuum. Too, both sorbed and free gas are found in gas shales, and the shales can be overpressured or underpressured. For the 21st-century explorer, working with gas shales means experimentation. There is little risk of not locating the resource; rather, the challenge lies in delivering high enough production rates at low enough costs to make money. Now, bountiful commodity prices offer the perfect environment to encourage widespread investigation of the many shale-gas plays in the U.S.

One of the most exciting plays bursting on the scene is the Fayetteville Shale of the eastern Arkoma Basin. Houston-based Southwestern Energy Co. believes that it has found a keeper in the Fayetteville, a black, organic-rich Mississippian shale that is the geological equivalent to the Barnett Shale and to the Caney Shale in Oklahoma. It occurs below the Pennsylvanian sands that are the major conventional gas reservoirs in the Arkansas Fairway of the Arkoma. (For more information on the Barnett, see "Barnett Shale," Oil and Gas Investor, April 2005.)

The firm keyed on the shale interval after it noted that some of its completions in the fairway in the Wedington sandstone, a unit embedded within the Fayetteville, produced greater volumes of gas than would be expected from its reservoir properties. The likely source of the pumped-up production was pinpointed as the Fayetteville Shale, and Southwestern began to consider the merits of the shale as a stand-alone objective.

During a full year of intensive study and mapping, the firm concluded that the Fayetteville compared favorably to the Barnett and other producing shale reservoirs. The Arkansas shale looked very promising from core and log analysis: it was thermally mature and its TOC ranged from 4% to 9.5%. The gas contents were between 60 and 220 standard cubic feet per ton, and gas-in-place was initially estimated at 58- to 65 billion cubic feet (Bcf) per section. The Fayetteville was a genuine exploratory play, however, as the prime areas of thick shale did not coincide with the developed fairway where Southwestern had its historical operating position. From a thickness of 50 feet in the fairway, the shale expands to as much as 325 feet in the counties to the east.

In early 2003, Southwestern launched a major lease acquisition program, which it carried out as close to the vest as possible. It succeeded well beyond its initial expectations: since 2003, it has amassed 630,000 net acres in the exploratory area of the play, in addition to the 125,000 net acres it already held in the fairway. On its new leasehold, its land costs averaged $50 per acre at year-end 2004, terms average more than nine years, and royalties are 12.5%.

"The part of the basin we were focusing on was a very rural area that had never had any real production, so we were able to lease without attracting wide attention," says Harold Korell, president, chairman and chief executive officer.

By mid-2004, Southwestern was ready to drill. Its first wells were in Conway County in its Griffin Mountain pilot area in 9n-17w and 9n-16w. It selected the area based on geologic parameters as well as its proximity to one of the two pipelines that traverse the eastern end of the Arkoma. The wells were drilled to depths of around 4,400 feet and fracture-stimulated. By year-end, Southwestern had 10 vertical wells on production, making between 100,000 and 500,000 cubic feet of gas per day apiece and little to no water. The company booked total proved reserves of 7.5 Bcf from 10 wells and 10 proved undeveloped locations during 2004.

As of the end of March, Southwestern had upped its total to 38 Fayetteville wells, and it had participated in an outside-operated well.

"Those 39 wells have been drilled in four counties in six separate pilot areas," says Korell.

Five of the pilots are in the undeveloped portion of the basin, where the shale is thick and few conventional wells produce; in addition to Conway County, the company has drilled wells in Van Buren County, in 10n-16w; in Faulkner County, in 8n-14w; and in Franklin County, in 10n-28w.

At the end of the first quarter, 27 wells were selling gas into the pipeline, four were marginal and were shut in, and the remaining wells were either being completed or waiting to be connected to pipelines. During the quarter, the producing Fayetteville wells made some 200 million cubic feet of gas. Three of the 39 wells were horizontal tests, with laterals ranging from 1,800 to 2,300 feet. Southwestern has released results on two of those, and a great fervor ensued after it reported an initial potential of 3.7 million cubic feet per day from its Stobaugh #2-1H. That horizontal well, drilled in its Gravel Hill pilot area in Conway County, is currently producing into sales at 2.4 million cubic feet per day. It has a 2,264-foot lateral that was stimulated with four frac stages.

Southwestern was instantly showered with questions from investors, stockholders and other operators about the Fayetteville: What are the recoveries per well? What are the costs and what rates are expected? How big can this play be?

"The answers lie in the production graphs," says Korell. "We have to produce the wells for a long enough period of time to extrapolate the ultimate recoveries. Our longest well has been on production just 280 days, and it's a vertical well in the fairway where the shale is thinner."

Based on its experience in the emerging trend, the company is comfortable stating ultimate recoveries for vertical wells in the range of 300- to 750 million cubic feet apiece. Generally, the verticals come on production at rates between 300,000 and 700,000 cubic feet per day, although several recent completions have posted more than 1 million per day. As for horizontal wells, it's too early too tell how much gas they may ultimately produce.

"A key question for us is how the horizontal wells will perform relative to vertical wells. If we can get multiples of vertical production rates with horizontals, and do it cost-effectively, that's the direction we will go."

Falling well costs are part of that equation. In the beginning, Southwestern's vertical wells were $500,000 to $700,000 each, including testing, coring and special logging expenses. At present, the company is spending $400,000 to $600,000 per well. Few horizontals have been drilled on the Arkansas side of the Arkoma Basin, however, so Southwestern is in new territory with these.

"We've learned rapidly on the first few wells," says Richard Lane, executive vice president. "We started out with a conservative design, and we're fine-tuning that as we gain experience."

Its early horizontals cost an average of $2.1 million, but going forward Southwestern expects the wells to come in as low as $1.5 million each. The first horizontal well took 32 days to drill; the second well only took 11 days. The third, which was deeper vertically, took 19 days. Increasing production rates are another factor. The Fayetteville wells must be stimulated to produce, and Southwestern has experimented with several different fracturing technologies, including nitrogen-foam and slick-water fracs. It has also employed microseismic techniques on a number of wells to calibrate fracture lengths and azimuths. Currently, it believes that the normally pressured Fayetteville section responds best to nitrogen-foam fracs, and it is designing its treatments to propagate transverse fractures. And, it continues to tweak the amounts and types of chemicals that it uses in its jobs.

"We're also looking at new coiled-tubing technology to speed up the jobs as well," says Lane. "Right now fracing a horizontal well takes three to five days, and we want to cut that time down substantially."

Location is an added issue. A notable characteristic of the Arkoma Basin is its structural complexity, with many down-to-the-basin normal faults and thrust faults. Initially, the company picked highly faulted areas for its pilots on the assumption that naturally fractured rock would yield better gas production rates, but now it is leaning toward less disturbed areas.

"We don't know all the answers about that yet, but in the more disturbed areas we might lose the fracs into the fault systems and don't contact the reservoir in the way that we want," says Korell. "It's looking now like the first area we drilled may not be our best area."

This year, Southwestern plans to devote as much as $100 million to the evolving play.

"We're focusing on determining the best way to contact the most rock per dollar, and on designing the optimum completion programs."

At present, the company is running three rigs, and it could raise that to as many as six to eight later this year, depending on the mix of horizontal to vertical wells it settles on. Although Southwestern has an immense acreage position, it isn't looking for partners, says Korell.

"We have a good balance sheet, strong cash flow and growing production. We also have the capacity to borrow, since we have a new $500-million, five-year debt facility. The Fayetteville is something we are going to do ourselves."

Nonetheless, the company does not underestimate the challenge: "It's a huge logistics and transportation project. This is a major manufacturing-style play in an area with very little infrastructure. We have a lot of work to do."

Caney and Woodford A related play is also astir in Oklahoma, in the correlative Caney Shale. The Mississippian-aged Caney has been a minor producer in Oklahoma for several years, according to the Oklahoma Geological Survey. Between 1998 and 2003, four Caney wells in McIntosh, Stephens and Love counties produced 700 million cubic feet of gas from depths between 2,600 to 3,900 feet. The OGS reports that the Caney has TOC contents of 2% to 4% in the Arkoma Basin, and from 4% to 5% in the Ouachita Mountain region. The older Woodford, an Upper Devonian/Lower Mississippian shale, is also a target: between 1961 and 2003, some 27 Bcf of gas was produced from 19 Woodford-only wells. The most prospective areas for the Caney and the Woodford are in the Arkoma Basin, where the maturities are right and the depths are reasonable. In Oklahoma's Anadarko and Ardmore basins, the oil-generative source rocks don't fall into the gas window until depths of more than 10,000 feet, while the rocks in the Arkoma Basin are in the gas window at depths of about 4,000 feet, says the OGS.

Quite a number of firms are now buying acreage in areas prospective for the Caney. One entrant is a start-up Australian company working in Okfuskee County, on the northern edge of the Arkoma Basin, just as it climbs up onto the Cherokee Platform. Tomahawk Energy has partnered with Shreveport, Louisiana-based Metro Energy Group Inc. on the 5,000-acre Snell Heirs project. Metro operates the project and is the largest stockholder in Tomahawk. To date, the partners have purchased two existing wells and drilled 15 new wells on the project; five of its wells are shallow twins targeting conventional reservoirs.

In this area, the Caney is found at depths of 3,300 to 3,600 feet, is thermally mature, and attains thicknesses of 130 to 150 feet. Gas contents are between 50 and 250 standard cubic feet per ton, and gas-in-place is estimated in the 20-Bcf per section range. Data from one well, the Snell Heirs #4-13, showed TOC of nearly 5%.

The companies currently have two producing Caney wells and three producing Woodford wells, says Rick Holcomb, director and vice president of Metro Energy. Seven additional wells are being completed.

"We're in the midst of a major program, both drilling and leasing," he says. "Without giving numbers, the Woodford completions appear to be very good wells. Long-term, we think the Caney will have the better reserves of the two, but we're still developing just the right completion techniques for it."

The Woodford is only about 40 feet thick in the Snell Heirs area, and the partners began to look at it after seeing some success to the south in Pittsburg County, where Houston independent Newfield Exploration is testing the Woodford with horizontal drilling.

"Right now we are completing seven wells and running lines to connect them to the gathering system. We plan to start drilling again in August, at the rate of two to four wells a month. Some of those wells will be horizontal, in both the Caney and Woodford."

Metro estimates that the average Caney/Woodford vertical well costs $500,000 to drill, complete and tie into sales.

"We're trying to determine how to complete the wells, since the Woodford has turned out to be such a pleasant surprise. We have a lot of Caney behind pipe that has had excellent gas shows, and we may go with dual completions."

Another very active program is ongoing in neighboring McIntosh and Hughes counties. Here, Castle Rock, Colorado-based Citrus Energy and Oklahoma City-based Oklaco Holdings are developing the Caney on a 70,000-acre leasehold. Tulsa-based Williams Cos. also recently joined the project. At present, Citrus and Williams both are running a rig in the shale play. The companies picked this part of the basin because the Caney had a history of good shows, including free gas that was liberated during air drilling. The shale, which is found at depths of 4,000 to 4,500 feet, offers about 50 to 150 feet of net effective pay. Citrus and Oklaco have acquired a number of wells and drilled about a dozen vertical and 10 horizontal Caney wells. The Wild Turkey #1-7, a vertical well completed in early 2004, flowed 1.13 million cubic feet of gas and six barrels of condensate per day from the shale.

According to IHS Energy, the well made 180 million cubic feet of gas during its first eight months onstream. Now most of the program's focus is on horizontal wells. The first series of horizontals was drilled with 2,000-foot laterals, and the most recent ones have featured 2,500-foot lengths.

"We know there is plenty of gas in the rock," says Keith Sackett, petroleum geologist and a partner in Oklaco. "Learning how to complete the wells is the key challenge. We're in the process of unlocking the mystery of how to fracture the Caney."

The companies are doing large slick-water fracs, working on staging the fracs, spacing out the perforations in the horizontal legs, keeping the fracs in zone and deciding what fluids to introduce into the formation. Six of the horizontals are in various stages of completion, and four have not been completed.

"On half of them we are encouraged," he says. "The other half we are still trying to understand what is going on in the subsurface after the frac."

On two wells, the companies used microseismic techniques to monitor frac effectiveness. One survey clearly showed most of the frac energy was lost to the underlying Hunton.

"If you are in an area where the Hunton has porosity, fracing into water is a problem. If the Hunton is either tight or absent, you can stimulate and not worry about water."

The companies are encouraged with their results to date and are moving forward in the Caney.

"We're close to having this field figured out. We expect to have a good-sized Caney play to develop."

And as for the Woodford, leasing plays are under way in several basins for it and for correlative shales. Bend Shale Another shale-gas play is beginning to bloom in the southern part of the Texas Panhandle in the usually quiet Palo-Duro Basin. The Lower Pennsylvanian Bend Shale is the target in an area that includes most of Motley and Floyd counties, and continues into Briscoe County. The shale in this region is thermally mature, reaches gross thickness of between 500 and 1,000 feet, and occurs at depths between 7,000 and 10,500 feet.

Legacy Petroleum, a small, private firm based in Arlington, Texas, kicked off the play a couple of years ago. Legacy had acquired a leasehold in western Motley County on a prospect that keyed off of a 1950s Granite Wash discovery. That well had tested gas and condensate but was never produced. Scattered offset wells were drilled in the 1970s, but these also were not produced due to the sparse infrastructure and lack of markets. Legacy thought it was time to revive the fallow area after the combination of higher gas prices, better completion technologies and the construction of a high-pressure pipeline through the basin changed the picture.

In 2003, Legacy partnered with PetroGlobe Inc., a Calgary independent, to drill the Cogdell #1-01 as a twin to the original discovery. The new well was drilled to 9,300 feet, and it intersected some sand stringers in the Granite Wash. Legacy fractured the interval with disappointing results, however, so it moved uphole to the Bend Shale. During drilling, the contractor had lost circulation in the 575-foot-thick shale, indicating that it was highly fractured. Legacy attempted a small frac over a 14-foot interval between 8,529-43 feet. Quite surprisingly, the well flowed back at the rate of 2.8 million cubic feet of gas per day, along with condensate, at a bottomhole pressure of 2,440 psi. Tulsa-based Vintage Petroleum moved swiftly into the play, buying a portion of Legacy's interests and taking over operations of the Cogdell well. It also launched an aggressive leasing program.

In late May 2005, Vintage had accumulated more than 130,000 net acres in the Palo-Duro. The company has noted that the average TOC in the Bend Shale is about 2%, half that of the Barnett Shale's 4.5% TOC, but that the Palo-Duro shale attains net thickness of 300 to 600 feet, in comparison to net thickness between 100 and 500 feet in the Barnett. Obviously, the hope is that the greater thickness of the Bend will compensate for its lower TOC values.

At present, Vintage has drilled and extensively cored two additional wells. The #1 Echols 2 is about 1.3 miles southwest of the Cogdell well, and the #1 M. Burleson Ranch "60" is about seven miles southwest of the Echols, both in Motley County. The operator is sending the core data from those tests to several firms that are designing fracture stimulations. By the third quarter, it expects to have a frac program selected for the shale. Vintage hasn't yet decided if it will frac both wells with the same design, or whether it will frac the first one and then tweak the design based on results. The company is holding its well information very tight, but Robert Phaneuf, vice president of corporate development, did allow that indications were positive, when addressing investors at the UBS Global Oil & Gas Conference.

"To date all the information we have received from the cores are not disappointing to us," he said.

One of the companies that jumped on the Bend Shale early was Vancouver-based Tyner Resources. Robby Robson, president of Tyner Texas, began working with Arlington-based La Esperanza Oil & Gas in late 2004. He brought both Tyner Resources and Calgary-based Bankers Petroleum into the play. Bankers Petroleum has amassed some 240,000 net acres in the basin, and Tyner has acquired a 100% interest in 10 sections. It also has an option to acquire an additional 100% interest in 10 sections from Bankers.

"In January, leases were $10 per acre; the leases are $50 to $80 per acre today," says Robson. "The terms were five years, and now the leases have 18- to 24-month drilling commitments."

Indeed, the Palo-Duro should enjoy a healthy spurt of activity in the months to come. This year, Tyner plans to drill three wells, one in Motley County near the Legacy well and two in Floyd County. The company has teamed with Louisiana-based operator Apollo Energy Operating Co., which also has acreage in the play, on a one-year rig contract. The first Tyner well is expected to spud in July. Each well should take about a month to drill, and a completed well is expected to cost between $1.3- and $1.5 million, says Robson. Plus, Bankers plans to drill up to four wells on its extensive position this year, with the first expected to spud in the third quarter, and Abilene-based Geosurveys Inc. has staked a well in northeastern Floyd County.

Other operators working the play include Austin-based operator FieldPoint Petroleum Corp., which has acquired a 3,235-acre position in Floyd County. The company reports that it paid an average of $25 per acre for its leases, with an average royalty of 20%. PetroGlobe, one of the original partners in the Legacy well, has signed a new agreement with Vintage for a 10% interest in the 63,000-acre Cogdell Ranch property. Additionally, Texas Drilling Observer has reported that Quicksilver Resources and Gunn Oil are active in the basin.

"The play is just now beginning to unfold," says Robson. "It seems to compare favorably to the Barnett Shale, and that's what everybody hopes it is."

Antrim and New Albany Devonian shales in the Appalachian Basin have been steadily producing natural gas since the 1920s, and more than 21,000 wells have been drilled to tap this resource. The shales extend from southwestern New York to eastern Kentucky and central Tennessee, and include the Ohio, the Rhinestreet, Dunkirk and Marcellus shales. Upper Devonian shales are also gas producers in the Michigan and Illinois basins. However, the New Albany and Antrim shales exhibit some striking differences from other gas shales. The Antrim and New Albany contain biogenic gas, generated by anaerobic bacteria. These shales are not thermally mature, although they are rich in organic content. They also produce considerable volumes of water along with their gas, and the gas-prone portion of the shales occurs around the basin margins.

To date, more than 7,800 wells have been drilled in the Antrim Shale, which is productive in an area of northern Michigan centered in the counties of Antrim, Crawford, Oscoda, Ostego and Montmorency. The Antrim ranks as the dominant producing reservoir in the state, and in 2004 it contributed about three-fourths of Michigan's annual gas production of 260 billion cubic feet equivalent (Bcfe). Typically, Antrim wells range from 400 to 2,000 feet deep, cost about $170,000 to drill and complete, and produce 400- to 800 million cubic feet of gas. Initial rates after six to 12 months of dewatering are 125,000 to 200,000 cubic feet per day. After producing at those levels for up to two years, the wells decline at about 8% per year during a 20-year lifespan.

Fort Worth-based Quicksilver Resources is the most active operator in the Antrim. The company started drilling Antrim wells in 1991, and today owns interests in nearly 3,000 producing Antrim wells. It produces 65 million cubic feet of gas per day, has 523 Bcfe of proved reserves and 200,000 acres of leases in the play.

"The Antrim is a huge resource, and we are constantly trying to improve our techniques to get more gas out of the ground," says Jeff Cook, senior vice president of operations.

Last year, Quicksilver drilled 44 net wells in the Antrim; in 2005 it plans 51 net wells.

"We're working on several projects that we hope will extend the play," says Mark Whitley, vice president of operations and engineering. "And, we are looking at what we can do to make the wells more economic."

The Antrim is a naturally fractured reservoir, and vertical wells have been the technique of choice. The company is investigating prospecting methods to identify areas that have fracture swarms, so it can potentially open new areas amenable to vertical wells. It is also drilling horizontal wells.

"Over the years we have tried vertical wells in the Antrim in several places, and now we're excited about horizontals," says Cook.

Last year, Quicksilver drilled three horizontal wells, and it plans several more this year. Additionally, it is bringing some of the fracturing techniques popular in the Barnett Shale play to its Michigan horizontals. Quicksilver is also considering dual-lateral wells, designed to tap both the Lachine and Norwood members of the Antrim. A nonorganic shale separates these intervals, so they are not easily stimulated together.

"The Antrim contains about 16 Bcf of in-place gas per section. It offers enough promise that we are trying several different techniques to improve recovery," says Whitley.

Quicksilver is also the major operator in the Illinois Basin's New Albany Shale, a formation correlative to the Antrim. The New Albany has seen fits and starts of activity over the years, often teasing operators with more promise than it has delivered. Water production has been problematic, and gas production has been spotty and unpredictable in many parts of the basin. Since entering the New Albany in 1995, Quicksilver has drilled or acquired 227 wells in southern Indiana and northern Kentucky, including 37 wells that it drilled last year.

This year, Quicksilver plans to drill 10 New Albany wells. The company has proved reserves of 29 Bcfe in the New Albany, and produces 7 million cubic feet per day from its Corydon Field, which accounts for two-thirds of Indiana's total gas production. At present, it holds 195,000 net acres of leases in the play, extending from the southern Indiana counties of Washington, Harrison, Floyd and Crawford into northern Kentucky's Meade, Hardin and Hart counties.

"The New Albany Shale covers the entire basin, but we are playing it up against the southeastern edge," says Cook. "It's a solid, good, everyday place to drill wells and get an acceptable rate of return."

In this area, the shale is about 100 feet thick and occurs at a depth of 700 to 1,000 feet. The main target is the 30-foot Clegg Creek interval. Estimates of gas in place range from 7- to 10 Bcf per section. The New Albany has been sparsely developed, and part of the problem has been a lack of infrastructure.

"There was no readily accessible market for our gas, so we laid a line across the Ohio River to Meade County, Kentucky, where we have additional production and two sales points," says Whitley.

To date, the majority of Quicksilver's New Albany wells have been vertical tests in the core area in Harrison County, Indiana, and Meade County, Kentucky, but the company has also drilled 15 horizontal wells. A dozen of these have been outside the core, in areas that were either only marginally productive or not productive at all.

"We drilled the wells, ran casing and put them online without stimulation," says Whitley. "We have horizontal wells that are making from 100,000 to 300,000 cubic feet of gas per day, along with a few wells that were not successful."

At present, the company is testing its first two Barnett-style horizontal wells, in which it cased, cemented and hydraulically fractured the New Albany section. As in the Antrim Shale, the presence of natural fractures is a key to economic production. In addition to its horizontal drilling program, Quicksilver is using both geophysical and geochemical data to locate areas with fracture swarms.

"If we know where the fracture swarms are, we may not need to drill horizontal wells. Vertical wells work very well if we can intersect the fractures. Because Quicksilver is also active in the Barnett Shale, it has a yardstick by which to compare its shale efforts. "So far, the Barnett is head and shoulders above these other shale plays," says Whitley.

"The Barnett has a tremendous amount of gas in place per section, from more than 200 Bcf in the core down to 50 Bcf on the far edges of the play. That contrasts to 16 Bcf per section in the Antrim."

And, the Barnett is overpressured, while the Antrim and New Albany are at hydrostatic, or are slightly underpressured. Too, the Barnett contains thermogenic gas, while the Antrim and New Albany contain recently generated biogenic gas.

"Nonetheless, the New Albany and Antrim shales do have natural fractures, which the Barnett does not have to the same extent, and they do contain significant volumes of gas. The challenge is to find the right areas to drill and to develop the drilling and completion techniques that allow economic access to that gas."

Quicksilver is also looking to expand into other promising shale plays.

"Shales require a different mindset, and we've been working with shales for a long time," says Cook. "We have a wealth of experience, and hopefully that gives us an edge in finding the next big play."