When the Age of Shales dawned less than a decade ago, the Woodford was an early and obvious target. The Upper Devonian/Lower Mississippian shale was widely known as a formidable source rock, responsible for the hydrocarbons in many legendary Midcontinent fields.

Although the Woodford sprawled across multiple basins, explorers were quick to zero in on the Arkoma in eastern Oklahoma. This area was considered most prospective, as thermal maturities were high and depths were reasonable. The hothouse Arkoma had incubated the Woodford into a fine, dry-gas reservoir, and work by such pioneers as Newfield Exploration Co., Devon Energy Corp. and Chesapeake Energy Corp. soon brought a major gas play to fruition.

Other Oklahoma basins held thick, rich Woodford sections as well, but in the early 2000s the industry was focused on dry gas. In the Anadarko and Ardmore basins, Woodford rocks didn’t dip into the gas window until depths of more than 10,000 feet. Production of liquids—both oil and condensate—from horizontal shale wells was beyond the technical pale, and formations at depths of more than 10,000 feet were too challenging to drill.

That didn’t stay the case for long, however. Rapid and revolutionary changes in shale drilling and completion techniques have now broken through both the depth and the liquids barriers.

These days, huge new areas of the Woodford are open to exploitation. Indeed, there are four distinct Woodford gas-shale plays in Oklahoma, says Brian Cardott, organic petrologist with the Oklahoma Geological Survey.

“The main Woodford shale-gas play is in the Arkoma Basin, where thermal maturities are 1.15% to 3% Ro (vitrinite reflectance, a measure of thermal maturity),” he says. “On the Anadarko Basin shelf, it’s a gas and condensate play and maturities are 1.1% to 1.5% Ro.”

There’s also a gas and oil play in the Ardmore Basin, where Woodford maturities are generally below 1.2% Ro. Finally, there’s even a vertical, biogenic methane play (not a subject of this article) in the Cherokee Platform, in northeastern Oklahoma, where the shale occurs at depths of just 1,000 feet.

Between 2003 and 2010, operators have drilled 1,058 horizontal and 308 vertical Woodford wells in the Sooner State. Additionally, 30 vertical wells have targeted Woodford along with other zones, says Cardott. According to state records, 1,200 Woodford-only wells have made 562 billion cubic feet (Bcf) and 1.48 million barrels of oil and condensate since 2004.

For Oklahoma, the Woodford shale has truly been the gift that keeps on giving. First, the world-class source rock generated the oil that filled many grand, old conventional fields, and now it’s a reservoir in its own right.

Cana Shale

A swarm of top-drives have settled in Canadian County. Here, the Woodford shale is enjoying fresh attention as a liquids-rich reservoir, the industry’s new penchant.

The Anadarko version of the Woodford is a slice of the shale that resides at just the right depth and thermal maturity to yield rich gas and condensate. The play currently covers an area just west of Oklahoma City, on the eastern flank of the great Anadarko Basin.

In general, the Anadarko Woodford, also called the Cana Woodford, is some 100 to 300 feet thick. Operators are concentrating on areas where it is rich in liquids, at vertical depths from some 10,000 to more than 14,000 feet. Farther into the basin deep, dry gas prevails.

Devon Energy Corp. opened the red-hot Cana Woodford play, named for its focal point in Canadian County, in 2007. It started with recompletions and plug-backs in a single-rig program. Today, the Oklahoma City-based independent runs nine rigs and makes 100 million cubic feet equivalent per day net from the shale.

Its program is on a steep upward trajectory: it will go to more than a dozen rigs by year-end. Indeed, Devon just updated its 2010 Cana drilling plans—it now expects to drill 100 wells instead of the previously announced 80.

The development of the Cana Woodford has been lightning fast. In 2006 and 2007, Devon was pushing its Barnett shale play in North Texas hard into the horizontal realm. “We were looking for new places to take the technology,” says Brad Foster, senior vice president for Devon’s central division.

An early effort was in the eastern Oklahoma wedge of the Arkoma Basin, where the Woodford is a shallower reservoir. Devon developed a solid program there; it currently holds 57,000 net acres and makes some 80 million cubic feet a day net. It continues to run four rigs in that play.

“Initially, we thought the Anadarko Woodford was less attractive than the Arkoma Woodford,” says Foster. Because it was some 4,000 to 5,000 feet deeper, the Anadarko play was considered beyond the limits of economic extraction.

However, the industry’s comfort with deep, horizontal shale plays increased dramatically as North Louisiana’s Haynesville play began to blossom.

“That’s when we took a serious look at the deep Woodford. It was quite different from the shales we had experience in,” he says.

As Devon began to work with the deep Woodford in 2007, its appreciation for the shale grew. It soon launched a major leasing program. Today, Devon holds 230,000 net acres, mainly in Canadian, Blaine, Caddo and Dewey counties. About two-thirds of its acreage is in the rich-gas area, which Devon considers its core. The remaining third is to the southwest, where the play turns to dry gas as the depths increase.

To date, Devon has drilled more than 60 wells. Typical wells take 50 to 60 days from spud to rig release and cost between $7- and $9 million, depending on depth. The Cana play is overpressured; Devon completes its wells with the plug-and-perf method, and runs some 12 slickwater frac stages per 4,500-foot lateral.

Inside its core, a dry-gas reserve is 6 to 6.5 Bcf per well, and liquids boost that to 8 to 8.5 Bcfe per well. Some areas deliver wells with estimated ultimate recoveries (EURs) as high as 11.5 Bcfe.

“In the Cana Woodford, it was just two years between our vision and substantial production,” says Foster.

Initial rates are typically 4- to 6 million cubic feet a day, and can reach up to 10 million a day in the drier areas. “We keep our wells choked back, to avoid problems with embedded proppant. We rarely open a well past a 20/64-inch choke,” he says. “Our initial declines are 55% for the first year.

“As we continue to have success, we are increasing our activity. The Cana is profitable at today’s prices, and we are drilling to capture our acreage position.”

Each well holds 640 acres, but eventual spacing will be much tighter. Devon and Cimarex Energy Co. currently have a joint project to determine drainage. Devon has drilled a set of horizontal wells 500 feet apart, on 70-acre spacing, and Cimarex has a similar project with wells spaced 660 feet apart.

“We just turned on our project a month ago,” says Foster. “By year-end, we hope to have a firm idea of the best spacing. From our work in the Barnett, we know that determining the optimal spacing early on is crucial.”
Devon’s recoverable resource on its Cana Woodford position is an amazing 10 trillion cubic feet equivalent, or more than 1.7 billion barrels of oil equivalent (BOE). “Original in-place gas in the play is 200 Bcfe per square mile, and that’s outstanding. It’s an enormous opportunity,” says Foster.

Today, with the superior returns delivered by its rich gas, the Cana Woodford play ranks as a top shale opportunity. “This play gives us the option to go to the vault and get the resources out of the ground when commodity prices are right.”

And, it’s directly outside Devon’s front door, in a state with a friendly, pro-business attitude and predictable regulations. Toss in a strong service sector and great access to markets, and its appeal is indisputable.

Shale Tour de Force

Cimarex Energy Co., Devon’s partner in the downspacing project, also has a major Cana Woodford program under way. And it too was an early mover.

The Cana Woodford is Cimarex’s first commercial resource play, says Tom Jorden, executive vice president. Denver-based Cimarex has a long history in western Oklahoma, through predecessor company Key Production Co. “Our oldest legacy asset was in western Oklahoma, and our first regional office was in Tulsa.”

A few years back, a couple of Cimarex geoscientists began to advocate a close look at the Anadarko Woodford. The operator was quite familiar with the section, and it had deep relationships with landowners, service companies and vendors in the region.

It also had a small legacy position in Canadian County. In early 2007, rumors from the field indicated other operators were beginning to probe the Woodford shale there. Core had been pulled in high secrecy on one well, and gas had reportedly flowed at surprising rates from another vertical completion.

Cimarex was already evaluating a 7,000-acre Woodford deal generated by a small prospect shop. After confirming the swirling speculation, it pulled the trigger on the purchase.

“That brought our Canadian County position to some 12,000 acres,” says Jorden. Cimarex put in motion its own leasing efforts, buying along depth contours from Dewey and Blaine through Canadian and into Grady counties.

Early on, the explorer bumped into brokers working for Devon, and before long it began to see competition from Questar E&P, Marathon Oil and Western Operating Co. The neighborhood was getting popular.

Cimarex drilled its first well in the summer of 2007, and sold its first Woodford gas in January 2008. The learning curve was precipitous: “We had challenges from stabilizing the holes to figuring out the appropriate mud systems to designing the proper completion techniques,” says Jorden.

“Still, our first wells looked to be commercial.” The company was getting rates of 3 million cubic feet a day from 2,500-foot laterals—not sterling, but quite encouraging.

The company pushed forward, continuing to drill and grow its position until the fall of 2008. That’s when the collapse of the financial markets—and commodity prices—required a gut check.

Cimarex was in the midst of evaluating a 40,000-acre block being offered for sale by Chesapeake Energy. It was prime real estate, smack in the heart of the Woodford play. “We really liked the block. It was well positioned and a good portion of it was held by production,” says Jorden. “We saw this as an opportunity that had long-term strategic importance to the company, so we went ahead and closed the deal.”

The $180-million transaction was seminal. It brought Cimarex’s Cana Woodford position to nearly 100,000 net acres, and made the shale play a key piece of its portfolio.

Meanwhile, the financial world continued to implode, and Cimarex played defense. From 43 operated rigs at the end of September 2008, the operator went to three in the winter of 2009. Those were rigs under long-term contracts, and they were drilling in the Woodford.

Completely aside from the broader financial issues, Cimarex was also grappling with technical problems in its completion attempts. “We were getting spotty results on our stimulations. On a well with nine to 10 stages, we might get proppant away in only two stages,” says Jorden. “The rest of the stages would screen out.”

The company halted all completions. It continued to drill and case its Woodford wells, but left them waiting on completion. It formed an interdisciplinary task force within Cimarex that was mandated to solve the problem however it could.

The task force zeroed in on near-wellbore constriction as the culprit. “One of our very talented completion engineers came up with the idea to pump a mixture of hydrofluoric mud acid,” he says. That was in addition to the hydrochloric mud acid that the company had routinely used.
It was a true “eureka” moment. The new mud-acid formula made an immediate and dramatic difference. Proppant went into the reservoir unimpeded, and Cimarex restarted its completion program in the middle of 2009.

“Today we are able to drill and complete wells in the Cana play as designed,” observes Jorden.

To date, the company has drilled or participated in more than 100 wells in the play, and currently keeps between seven and nine rigs at work. Its typical Woodford well runs $7.5 million and will make an average of 4.9 million cubic feet of 1,200-Btu gas and some 70 barrels of condensate per day during its first 30 days on line. Estimated ultimate recovery is 8.8 Bcfe.

“We are getting excellent results. Our after-tax rate of returns are very attractive,” he says. Cimarex’s current net Woodford production is 75 million cubic feet equivalent per day, with its product stream split 65% gas, 30% natural gas liquids (NGLs) and 5% condensate.
“We love this play, and we love the balance it brings to our overall portfolio,” says Jorden.

Still, the Cana Woodford play is young. Most drilling, by Cimarex and other operators, has focused on six to eight townships in the heart of Canadian County.

“We have hundreds of wells to drill, and there’s a lot of acreage that has yet to be evaluated,” he says. “We don’t yet know how big this will be.”

Practice Makes Perfect

Across the state, eastern Oklahoma’s Arkoma Woodford play is rocking along in Pittsburg, Coal and Hughes counties. Most of Oklahoma’s horizontal Woodford drilling has been in this corner of the Patch, and it continues to support activity. Nearly 30 rigs are currently at work in the Arkoma Woodford, contracted by a who’s who of operators including Newfield Exploration, BP, Devon and ExxonMobil.

One company that appreciates the charms of the Arkoma version of the Woodford is Denver-based SM Energy Co. (which recently changed its name from St. Mary Land & Exploration Co.). SM Energy holds 32,000 net acres, mainly in Coal County and almost all held by production. It has drilled 44 Woodford wells since it kicked off its program in 2005, and it produces 55 million a day gross and 35 million net from the shale.
It currently runs one rig, and will shortly add another. “We’re picking our activity back up,” says Paul Veatch, the company’s Tulsa-based senior vice president.

The ramp-up in rigs in a dry-gas area may surprise some observers in these days of sagging gas prices. That’s because the best-kept secret in U.S. gas shales may be eastern Oklahoma’s Woodford play.

“As a company, the Woodford is our most mature shale play,” says Veatch, “and it’s had the most dramatic improvement in recoveries.”
The Arkoma Woodford has some unique factors that allow it to deliver solid economics: lower costs and improved completions have pushed returns solidly into the black.

“We can drill and complete wells for less than $4 million in our shallowest areas, and less than $5 million in the deeper portions of our acreage,” says Veatch. Depth to the shale ranges from 8,000 to 10,000 feet across its position.

“That, coupled with our recent well performance, makes the Woodford economic.”

Certainly, today’s Woodford wells are not anything like early efforts. Longer laterals, closely spaced stages and higher-volume water fracs have all contributed to stronger recoveries. Today, SM Energy typically drills laterals in the range of 4,900 feet and fracs up to 18 stages per lateral.

“We also employ the simul-frac technique,” says Veatch. “We think it gives us more stimulated rock volume, and it makes better wells.”

Optimum spacing in SM Energy’s area is some 80 acres per well, so it typically drills four wells in a 320-acre unit. “We frac the outside two wells with two complete frac spreads at the same time, then we frac the inside two wells at the same time.” All four wells are flowed back together.

Results have been first-rate: SM’s type Woodford well recovers 3.4 Bcf and averages 3 million a day during its first 30 days on production. “The average EUR of our last 10 wells is 4 Bcf each,” says Veatch. “But we are conservative, so we still make our capital decisions based on the type well.”

The Woodford play is one of those cherished assets that offers SM ultimate flexibility. “We understand the Woodford very well. It’s repeatable and low risk for rate and reserves,” he says. Without lease-expiration issues, the Woodford is a play that the company can accelerate or scale back in relation to other opportunities for corporate capital.

“We learned shales in the Woodford, and we’ve taken that experience to our newer plays in the Eagle Ford, Haynesville and Marcellus,” says Veatch. “Meanwhile, we still have a great many wells to drill in the Woodford.”

Green-Powered Gas

Another operator with plans to expand in the Arkoma Woodford is Lafayette, Louisiana-based independent PetroQuest Energy Inc.

In 2003, the independent embarked on a program to add resource plays to its portfolio. The Gulf Coast player decided to use about half of its cash flow to expand into longer-lived plays, says Charles T. Goodson, president, chairman and chief executive officer. Initially, it purchased positions in East Texas in the Travis Peak and Cotton Valley.

In 2004, PetroQuest entered the Hartshorne coalbed-methane play in Oklahoma’s Pittsburg County.

“The Hartshorne play has now been superseded by the Woodford, but we still have those shallow rights and CBM production,” says Goodson. Indeed, the happy occurrence of the Woodford shale play in the same area as the Hartshorne has strongly validated the company’s Midcontinent strategy.

As Newfield Exploration began to crack open the Woodford play, PetroQuest watched closely and elected to wait and see. Over time, it transitioned from an active CBM program—drilling as many as 100 such wells a year—to a shale program.

Between 2004 and 2009, PetroQuest made a series of leasehold acquisitions, growing its position to 45,000 net acres in the Woodford. It dipped its toe into the shale with 2,000-foot laterals and three to four frac stages.

“At first, we did not use 3-D seismic, and we found it very difficult to stay within section in the laterals,” says Goodson. Early Woodford wells were problematic: costs ran $5 million each, and IP rates were 1- to 2 million cubic feet per day. Ultimate recoveries scraped 2- to 3 billion cubic feet (Bcf).

Improvement was clearly needed.

By March 2008, PetroQuest had acquired 3-D seismic across most all of its leases. That has been a key technology: Woodford beds dip 5 to 8 degrees in the Arkoma, and are cut with many minor and occasional major faults. The 3-D data allow accurate imaging and precise well planning. Today, PetroQuest’s laterals stretch 4,500 to 5,000 feet and stay reliably in section.

Frac stages are now 350 feet apart, and frac clusters have been doubled per stage. The strategy of frac stage compression has yielded measurable success.

“These steps have dramatically increased well performance,” says Goodson. “Our Woodford wells currently have average IP rates of 5- to 7 million a day, and average EURs are 5 Bcf per well. Costs are $4.6- to $4.8 million.” In point of fact, its three most recent completions came on at an average IP rate of 6.8 million a day.

Indeed, the improvements have brought the Woodford’s breakeven economics to around $4.75 per thousand cubic feet. Basin-wide, finding and development costs run $1 per thousand cubic feet.

That’s right on the cusp at today’s prices. But, PetroQuest has an added boost. In May, the company announced a major joint venture with NextEra Energy Resources, a North American electric-power generator with some 18,000 megawatts of wind, natural gas and nuclear-fueled capacity.

While many in the fossil-fuel industry talk about partnerships with renewable-energy interests, PetroQuest is walking the walk. It has forged one of the first significant deals between a green-power heavyweight and an independent E&P firm.

In the arrangement, NextEra acquired a half interest in PetroQuest’s undeveloped Woodford acreage (some 20,000 net acres) and half of its proved undeveloped reserves (24.9 Bcfe). NextEra paid PetroQuest $60 million at closing, and the operator can receive an additional $28 million in future payments.

PetroQuest also gets up to $146.6 million in drilling carries, $54 million in the initial phase. If NextEra elects to continue the relationship at the close of that phase, it will fund the remaining $92.6 million.

Obviously, the $234.6-million JV has markedly changed PetroQuest’s cost structure. “This is a long-term relationship with our partner. We spent years (and capital) honing our Woodford capabilities and reducing risk in the play,” says Goodson. “Now the JV has dramatically lowered our go-forward F&D cost.”

Certainly, the JV ranks as PetroQuest’s most important corporate transaction. “It’s a financial decision to accelerate the recoupment of capital invested, and to accelerate development going forward,” he says.

At present, PetroQuest is running one rig in the Woodford and has added a second that will begin drilling in September. By year-end, it expects to have three rigs at work. It will raise that to four or five in the first half of 2011. “It’s a huge ramp-up,” says Goodson. This year, PetroQuest plans 15 operated Woodford wells.

Last year, the company completed four Woodford wells, two of which were drilled in 2008. Before the price bust in 2008, it was running three rigs and operating gross production of more than 60 million cubic feet a day. Current gross operated production is 50 million a day; net is 30 million. Given its aggressive program going forward, that volume will rapidly expand.

For PetroQuest, the Woodford has many attractive features. Oklahoma is an energy-friendly state that recognizes the benefits the industry brings. Surface access is forthright: this part of the state features flatlands to gentle, rolling hills. Gathering and transmission infrastructure is available and accessible.

“Compared to some of the other resource plays, the Woodford has flown under the radar. Lease costs and service costs have remained attractive,” says Goodson. “We are focused on generating good returns for our shareholders in a low-commodity-price environment, and we think we can do that in the Woodford.”

Oily Slice

Finally, the Woodford offers an area of oil potential. Southern Oklahoma is home to a distinctive play that’s a mix of oil and gas. In Carter and Johnston counties, Camarillo, California-based BNK Petroleum owns 13,500 net acres in the Ardmore, a narrow, structurally complicated basin wedged between the Arbuckle and Wichita uplifts.

In BNK’s portion of the Ardmore, a band of thick Woodford shale sits comfortably in the oil window at depths from 6,000 to 11,000 feet. “At first, the liquids were my big concern. I wasn’t sure we could produce it,” says Wolf Regener, president and chief executive.

The company drilled its first well in 2007 in Tishomingo Field. It has since developed 37.9 million BOE on its acreage, which produces solely from the Woodford. In most sections, it partners with Wagner & Brown, a long-time Midland-based independent. BNK’s current net production is some 1,100 BOE per day from the asset.

Today, it is concentrating on completions. “During the downturn, we didn’t frac out all the stages in our laterals,” says Regener. “Now, the economics on the frac outs are quite good.” The company operates some 30 wells in the field; about half of those were completed in one to three stages. “We still have about half of the stages in those wellbores to do,” he says.

At present, fracs are running about $200,000 a stage, using ceramic proppants. BNK is evaluating the efficacy of the ceramics—if it switches back to standard proppant, cost per stage will drop substantially. Nonetheless, it is experimenting with ceramics to get the best flows it can from the oily shale. “We are trying to induce permeability to get the liquids out of the way,” he says. The operator has also tightened its stages to 300 feet apart.

Additionally, BNK is getting ready to resume drilling, after a two-year hiatus. Downspacing is on the table. Currently, the field is developed on one well per section, and BNK is applying for a downspacing pilot with state regulators. “The Woodford is 330 feet thick, so we think there is definite downspacing potential,” he says.

Average well costs, which obviously vary with depth, run about $5.8 million. The use of 3-D seismic is mandatory—the Woodford outcrops just a couple miles northeast of the field, and drops off sharply to the southwest. “We have some good-sized faults that run through our leases,” says Regener.

Per-well recoveries are 900,000-plus BOE. Liquid yields fluctuate across the field; the wells make oil and condensate and get gassier as they are produced. BNK’s production is about 40% gas, and liquids comprise the remainder.

“We’re very happy with our position. I love the product split, and always have. It’s unique to find oil and gas in one field, and that’s what we have.”

Certainly, that could be the tag line for all of Oklahoma’s Woodford: it’s a unique reservoir that offers a treasury of products in one of the nation’s premier oil-producing states. Oklahoma is okay, and the Woodford is downright wonderful.