The Arkoma Shales

The Fayetteville Shale in north central Arkansas and the Woodford Shale in southeastern Oklahoma hold trillions of cubic feet of gas in place, and producers have been engaged in massive drilling programs to tap that gas.

One of the nation’s leading unconventional gas operators, Oklahoma City’s Chesapeake Energy Corp., estimated that the rich 200-ft- to 300-ft-thick shale sections under its holdings in the Fayetteville may yield ultimate recoverable gas reserves of 6 Tcf.

Houston’s Newfield Exploration Co. is even more sanguine about the potential of the Woodford. By that company’s calculations, its acreage in the southeastern Oklahoma shale play could hold a treasure trove of 3 Tcf to 6 Tcf of recoverable gas. Houston’s Southwestern Energy Co.—the biggest leaseholder in the Fayetteville—has built such a prime position that it has exposure to ultimate gross recoverable reserves of 11.2 Tcf.

Fistful of Fayetteville
With such a treasure trove in front of it, Southwestern invested US $1.2 billion in its Fayetteville Shale drilling program during 2008. Average well results have rocketed upward, climbing from 1.5 Bcf per well in 2007 to 1.9 Bcf a well last year. The company produced 134.2 Bcf from the Fayetteville Shale in 2008 and closed out the year at an astonishing 720MMcf/d. Going forward, it expects its 2009 Fayetteville production to hit between 229 and 232 Bcf.

To understand the target that Southwestern is pursuing today in the region is to appreciate how a little serendipity a few years ago played a significant role in the company’s remarkable growth in the play.

It all began in 2002 when the operator discovered that its older wells in the shallow Wedington sand-in the northwest Arkansas part of the Arkoma Basin were actually producing four to eight times more gas than should have been in place in that Mississippian-age sand.

“What we found was that we were getting gas contribution in those old, conventional wells from the surrounding 50-ft- to 70-ft-thick shale sections above and below the Wedington,” explained Harold Korell, Southwestern chairman and chief executive officer. “That’s when the first light bulb came on.” Still, 50-ft to 70-ft shale sections didn’t seem very prospective. So the company undertook a study of the eastern part of the Arkoma in north central Arkansas where the majors had drilled deeper wells through the Mississippian to look at the Arbuckle play during the 1970s.

Hands on Nomac Drilling Inc.'s Rig #25 are in the midst of Fayetteville drilling operations for Chesapeake Energy in White County, Ark. (Photo courtesy of Lowell Georgia)

“We found that the shale sections in the eastern part of the basin, particularly in Conway and Van Buren counties, were more than 200 ft thick,” recalled Korell. “That’s when the second light bulb went on for us — that we had thick shale targets in the Fayetteville, at depths ranging from 1,500 ft to 6,500 ft.”

The black, organic-rich Mississippian Fayetteville is the geological equivalent to the Barnett Shale in north Texas and Caney Shale in Oklahoma. The Fayetteville occurs below the Pennsylvanian sands that are the major conventional gas reservoirs in the Arkansas Fairway of the Arkoma.

The Arkansas shale is thermally mature and its total organic content (TOC) ranges from 4%to 9.5%. Its gas contents are between 60 and 220 standard cubic ft per ton, and gas-in-place is 58Bcf to 65Bcf per section. From a thickness of 50 ft in the Fairway, the shale expands to as much as 325 ft in counties to the east.

To unlock the Fayetteville’s potential, Southwestern initially focused on drilling horizontal wells, typically with 2,000-ft lateral extensions, so that the well bore could make more contact with the low-permeability shale rock.

In the Fayetteville Shale, Southwestern Energy believes it has exposure to 11.2 Tcf of recoverable gas reserves. Newfield Exploration, which holds 137,000 net acres in the Woodford Shale, believes that play could yield 3 Tcf to 6 Tcf of recoverable gas reserves.

At the same time, the company used a combination of both slickwater fracs and cross-linked gel fluids in its well completions. Sand was pumped into the shale reservoir in an effort to optimize the rate at which gas flowed back into the well bore.

At present, Southwestern drills its wells for an average completed cost of $3.1 million a piece. Laterals run 3,850 ft. During 2008, wells placed on production averaged initial rates of 2.7 million a day, up more than 1 million a day from 2007 rates. It has shifted to slickwater fluid completion on all its wells.

Recently, the company has been testing closer perforation cluster spacing in its horizontal wells. It is pleased with the results, gaining 20%to 25%improvements in early production. This could translate into corresponding increases in ultimate recoveries.

All told, the company has spud 1,230 wells in the Fayetteville play, of which it operated 1,015. At year end 2008, it had drilled and completed 804 wells, of which 726 were horizontals.

The company’s year-end 2006 company wide reserves totaled a little more than 1 Tcfe; its annual production, about 72 Bcfe. In 2008, total proved net gas reserves booked in the Fayetteville shale play alone were 1.5 Bcfe.

“So the potential of the Fayetteville far exceeds— by multiples — our current reserve and production profile,“ said Korell.

Major joint venture
Chesapeake Energy Corp. is another major player in the Fayetteville. In 2005 — after studying Southwestern’s experience in the emerging play — the company began moving aggressively. By the following year, it had amassed some 350,000 net acres it considered prospective, particularly in White County in the central part of the Fayetteville fairway, as well as in Van Buren, Conway, Faulkner, and Cleburne counties.

One of 28 ponds that Seeco has constructed in the Fayetteville play as a source for frac water.

The big attraction? Steve Dixon, executive vice president and chief operating officer, said, “We felt that at shallow depths of 2,500 ft to 5,000 ft, the Fayetteville wouldn’t be very costly, that its shale sections were thick enough over such a large area that it could have multiple Tcfs of gas reserves in place, and that the play was repeatable such that we could just drill well after well, build infrastructure and turn it very much into a gas manufacturing-type operation.”

That’s not all. Since the company is fracturing so many different types of shale wells throughout the country, it believed it could leverage that extensive knowledge into better approaches to drilling and completing Fayetteville wells.

Aubrey K. McClendon, chairman and chief executive officer, said, “Traditionally, the industry had to solve for geological risk every time it went out and drilled a well, but with the advent of horizontal drilling and better completion technologies, such as multi-stage, slickwater fracs, we’re no longer solving so much for geological risk as we are engineering risk.”

2006 was a relatively modest one for the producer in the Fayetteville. In 2007 and 2008, however, Chesapeake went at the play with a full head of steam.

Ultimately, the play will be developed on 80-acre spacing. “That means we can eventually drill about 4,500 new wells, each with ultimate recoverable reserves of 1.6Bcf,”McClendon said. “After royalties, we expect to net 1.4 Bcf per well. Multiply that by 4,500wells and it becomes clear that we’ve potentially captured about 6 Tcf of gas under our Fayetteville leasehold. So this shale play is very significant for Chesapeake.”

Then, in a stunning move, Chesapeake sold a 25% interest in its Fayetteville assets, including approximately 135,000 net acres of leasehold and production of 45MMcf/d, to BP America. The major oil company made the move into the Fayetteville in third-quarter
2008, putting a stamp of approval on one of North America’s homegrown plays. Consideration was $1.9 billion of cash and future drilling carries.

Today, Chesapeake’s 420,000 net acres rank it as the second-largest leasehold owner in areas it considers core and first tier. It produces approximately 180 MMcf/d of net gas (285million gross operated). By the close of this year, it expects those volumes to climb to 235 million net and 400 million gross operated.

The firm plans to run approximately 20 rigs through the year to further develop its leasehold. Nearly all of its 2009 drilling costs, or approximately $535 million, will be paid for by its joint-venture partner BP.

Lowering costs
A start-up in late 2004, Houston’s Petrohawk Energy Corp. wasted no time getting into both the Fayetteville and Woodford plays.

“Our decision to pursue prospects in the Fayetteville and Woodford is a part of our overall strategy to grow within gassy basins,” said Floyd Wilson, Petrohawk chairman and chief executive officer. “These activities were very complementary to our resource type drilling in the north Louisiana Cotton Valley play and other parts of the Midcontinent.

“So in the case of the Fayetteville and Woodford, it wasn’t like we were casting off in a new direction. They were simply different plays, new acreage, where we felt we could bring to bear our experience in horizontal drilling and modern frac technologies to create good economics.”

In the Fayetteville, Petrohawk started off drilling in early 2006.

“The challenge for every operator is getting costs down and turning the play into more of a manufacturing- style drilling program that’s repeatable, somewhat cookie-cutter, so that there’s not a lot of R&D work required on every operation,” Wilson said.

To lower costs, Petrohawk used high-angle and extended-reach drilling technology with polymer- and oil-based muds, said Weldon Holcombe, senior vice president of Petrohawk’s Midcontinent division. “This allows us to have less nonproductive time when drilling-fewer trips, fewer hole problems and less time running casing.”

In the completion phase of its Fayetteville horizontal wells, the company is using a series of up to eight openhole packers to isolate each 300-ft to 400- ft frac stage in the lateral sections of its wells while it sequentially stimulates each isolated section of the formation with very large, high-rate, slickwater fracs, preceding them with acid.

In 2008, the company drilled 143 horizontal wells in the Fayetteville on its 157,000 net acres. Its gross operated production was approximately 145MMcf/d at year-end. It focused on using cemented liners and increasing its average lateral length and number of frac stages.

At the beginning of 2008, only 4%of its wells used cemented liners, its average lateral length was 2,286 ft, it fractured six stages in a well. During the fourth quarter, 100% of its wells had cemented liners; lateral lengths averaged 2,655 ft, and 7.6 stages were fractured in each well.

These efforts paid off in superior completion rates, as Petrohawk’s initial potentials (IPs) on its Fayetteville wells grew from 1.9 million per day in the first quarter to 2.4 million in fourth-quarter 2008.

Oklahoma’s Woodford
The Arkoma Basin’s Woodford Shale play centers on southeastern Oklahoma’s Hughes, Coal, Pittsburg, and Atoka counties. This organic-rich, Devonian-aged shale is the most active play in the Sooner state.

Operators with sizeable positions in the Arkoma Woodford, which covers some 1,500 sq miles, include Newfield Exploration, Antero Resources, Continental Resources, Devon Energy, St. Mary Land & Exploration, PetroQuest Energy, and XTO Energy.

Average per-well costs in the play have been $5 million and recoverable reserves 3 Bcf, but operators appear to be successfully pushing well costs downward and ultimate recoveries upward.

The Mississippian/Devonian-aged shale ranges up to 220 ft thick, its TOC contents rise as high as 14%, and it has high silica contents, between 60%and 80%. Drilling depths range down to 11,000 ft. Woodford wells make little to no water, and most drilling is in a rural corner of Oklahoma. Plenty of old vertical wells in the area lend well-control data, meaning few surprises.

Houston-based Newfield Exploration is the marquee company in the Woodford shale play. The company began its involvement in 2003. It made its first Woodford Shale discovery that year. Its first horizontal well came onstream in 2004.

To date, some 750 horizontal Woodford wells have been drilled by industry, and Newfield has operated 225 of those. The company has 165,000 net acres of leases. This year, it plans to run 11 operated rigs in the play. In mid-December 2008, its Woodford production surpassed 250 MMcf/d, and its total Woodford production volumes in 2008 increased 65% over 2007 levels.

Cost control is a prime objective of every E&P company these days, and Newfield notes that it has reduced its costs to drill a lateral foot of Woodford by more than 40%from2007 to 2008. The cost reductions came from faster drilling, pad drilling, refinements in completions, and increased lateral lengths. In 2006, Newfield’s Woodford laterals averaged 2,500 ft; this year it plans for laterals up to 5,000 ft long.

Additionally, the company has experimented with multilateral completions in the Woodford. Its first well featured 8,500 ft of lateral hole and had an IP of 13 million a day. During its first three months of production, the well averaged 8 million a day.

Newfield is also trying a super-extended lateral. This well has a 5,600-ft horizontal section and was completed with 12 frac stages. Initial rates have not yet been announced, but are expected to be released shortly.

Oklahoma native
For Oklahoma City-based Devon Energy Corp., its entry into the Woodford in southeastern Oklahoma in early 2003 was a natural extension of its earlier success in the Barnett in the Fort Worth Basin.

“When we bought Mitchell Energy & Development in 2002, we saw that the technology to get gas out of dense shale bodies as in the Barnett was really opening up,” said J. Larry Nichols, Devon chairman and chief executive officer. “And as we developed our knowledge and expertise in the Barnett, we started looking around the country for other places that would be prospective for shale gas.”

The Woodford, particularly in Coal and Hughes counties, looked very attractive, in terms of having the requisite thickness and geologic characteristics to apply the knowledge the operator had gained in the Barnett, he added.

Devon targets the shale at depths ranging from 6,000 ft to 10,000 ft. “It’s a pretty rich black shale, the thickness ranging from about 140 ft to 175 ft,” said Stephen J. Hadden, Devon senior vice president, E&P. “Potentially, the gas reserves under our acreage could be as much as 1 Tcf.

“As we learned with the Barnett, matching the right frac technology with a particular reservoir is always important when it comes to unlocking the optimum value in shale plays,” Hadden noted. “Early in the Woodford play, we tried some gel fracs, but later moved to slickwater fracs. We found them cheaper and more efficient, in terms of getting better production performance.”

Slickwater fracs, he pointed out, allow for higher pump rates and higher volumes of water and sand to penetrate a targeted formation such that an operator can optimally extend the fracture system and get more of the formation’s gas flowing into the well bore.

Another value-added technology Devon has brought to bear in the Woodford is 3-D seismic. “Being able to image a reservoir in great detail before we drill helps us avoid geological hazards that might be present in a shale formation and determine the optimal locations to position our horizontal wells,” Hadden said.

In the completion phase, the operator is also employing microseismic technology. “It’s a tool that allows us to track and map the path a frac job may take in a well bore, such that we can actually see how the frac is being distributed in a reservoir,” he said. “In short, it provides a good picture of how effectively we’re completing a well.”

To handle the increasing amount of production that will result from Devon’s stepped-up horizontal drilling in the Woodford, the company is continuing to expand its gas-gathering system in the region. It completed its $30 million Northridge gas processing plant with capacity to produce up to 200 million a day. The plant started operations in October 2008.

Certainly, the Woodford has been an incredible growth story. From modest production of some 25 MMcf/d (all from vertical wells) in early 2005, the black shale has grown to volumes of 550 million a day in mid-2008. When that’s added to the tremendous Fayetteville gas total of some 1 Bcf a day at year-end 2008, it’s clear that the Arkoma Basin shales have become a considerable