Haynesville Shale

Gone are the days of expansion and buoyant expectations. The industry has turned on a dime and, in the midst of world tumult and economic crises, companies are sorting through their prospects. In 2009’s dour reality, one play that remains at the head of most lists is the Haynesville shale.

The Jurassic Haynesville is prodigious and truly remarkable. It has every characteristic desirable in a shale reservoir: rich total organic carbon (TOC) content, excellent thickness, strong geopressures, wide areal extent, tough bottom seal and incredible homogeneity.

As rigs idle across the country, the Haynesville will be a bright spot of investment. Operators fortunate enough to hold swaths of Haynesville acreage are reallocating their capital to concentrate on development of this uncommon shale.

It’s that good.

The company that ushered the Haynesville onto the industry stage was Chesapeake Energy Corp. The Oklahoma City-based firm unveiled its Haynesville program with typical panache last spring. It made some bold statements about the potential of the shale, and sent people throughout the country scrambling for maps to figure out what exactly it was talking about.

Of course, Chesapeake was not the first to see the possibilities in the unique shale reservoir, but it was certainly the first to bring widespread attention to it.

At present, Chesapeake has 14 rigs working in the play, spread through Louisiana’s Caddo, DeSoto and Sabine parishes. Mid-summer 2008, it entered a joint venture with Plains Exploration & Production Co.

Chesapeake assigned Plains 20% of 550,000 net acres for $1.65 billion in cash and $1.65 billion in carried working interests. Going forward, Plains pays 50% of Chesapeake’s 80% working-interest costs until the carry is spent.

The company currently holds nearly 500,000 net acres in the play, exclusive of Plains, and produces 65 million gross cubic feet of gas per day from 16 horizontal wells.

For Chesapeake, the Haynesville proffers unbelievable potential. Its massive acreage position could allow it to develop 14 trillion cubic feet (Tcf) in recoverable reserves, based on a 50% risk factor on 29 Tcf of unrisked reserve potential.

At the close of 2009, the company plans to have 35 rigs at work in the Haynesville, an average of 25 to 26 rigs across the year. Conceivably, Chesapeake could be producing more than 600 million cubic feet per day net from Haynesville wells by the end of 2010.

“What makes the Haynesville so robust is the overpressured nature of the reservoir,” says John Sharp, Chesapeake geoscience manager, Louisiana district. Throughout the Haynesville, reservoir pressures range from 9,000 to 12,000 psi, and most of Chesapeake’s wells run around 9,800 psi. Pressure gradients of 0.85 to 0.9 psi per foot allow Haynesville wells to produce at far higher rates than wells in such shales as the Barnett or Fayetteville, where pressure gradients run in the range of 0.42 to 0.5 psi per foot.

Early Haynesville horizontals were excellent wells, and today’s completions are even better. Chesapeake’s last four wells have posted production rates in excess of 10 million a day. Estimates of ultimate per-well recoveries have climbed from 4.5 billion cubic feet (Bcf) recoverable to 6.5 Bcf, and some wells are now close to 8.5 Bcf apiece.

And, the play is epic: It spans an area 100 by 100 miles, from Harrison County, Texas, to Bienville Parish, Louisiana.

Clearly, the Haynesville has the flow rates, reserves and repeatability to deliver solid returns even at low-end gas prices. At Nymex prices of $5 per thousand cubic feet and assumed capex of $7 million per well, the Haynesville can deliver a 20% rate of return. Indeed, according to Chesapeake’s calculations, prices have to be below $3.88 per thousand before returns on a 6.5-Bcf equivalent (Bcfe) well, even given an 80% first-year decline, drop below 10%.

“The economics are obviously very attractive,” says Sharp.

Chesapeake has drilled and completed more horizontal wells than any other operator in this new play. It has already improved its costs and sees potential for more efficiencies.

“With the use of oil-based mud and by paying close attention to geosteering operations, we are drilling our laterals in fewer days and with fewer problems than before,” says Sharp. In less than a year, average drilling times for horizontal Haynesville wells have dropped from between 50 and 60 days to between 40 and 50.

Also, Chesapeake is using superpads wherever possible, a strategy that lowers costs and reduces its footprint.

In the superpad approach, two 640-acre units are developed via two pads built along the section line. Four wells with 4,500-foot laterals are drilled to the north on each pad, 660 feet apart, at 80-acre spacing. Each pad also has four wells directed south. Per-section recovery is estimated at 52 Bcf, so each two-pad development accesses 104 Bcf of gas. Superpad drilling also allows such efficiencies as running gathering lines down section lines.

Nonetheless, the Haynesville can be recalcitrant. Big issues are mud-motor and measurement-while-drilling (MWD) tool failures, due to reservoir temperatures that range from 300 to 350 degrees Fahrenheit. Naturally, the failure rates of these directional tools bear heavily on costs and drilling times in the lateral holes. The availability of specialty proppant for completions is another trouble spot; on each well, Chesapeake typically fracs eight to 10 slickwater stages, with some 2.6 million pounds of proppant.

Furthermore, as remarkably regular as the Haynesville is, its depth, thickness and permeability do vary. Structural elements, such as faulting and higher dip rates in some areas, can offer added complications.

“Generally speaking, initial well quality is more a function of matrix permeability, rather than thickness or depth,” says Sharp.

“But we are very early in this play in terms of drilling.”

Elm Grove Monsters

A firm that is enjoying a run of fabulous Haynesville wells is Petrohawk Energy Corp. The Houston-based company had a hefty position in North Louisiana’s Elm Grove and Caspiana fields before the Haynesville burst forth.

On its leases on the superlative Elm Grove structure, Petrohawk had been drilling horizontal Cotton Valley wells in the Taylor sand for several months and encountering fabulous rates and pressures. Intriguingly, the overpressured Haynesville lay 1,000 feet deeper. As data on the reservoir properties of the Haynesville were revealed, the company recognized that the shale was a legitimate target.

Petrohawk had previously studied one Elm Grove well that had penetrated Haynesville, and it engineered its initial shale test in the vicinity of this well with a long lateral and multiple frac stages. The techniques were similar to those used in its Fayetteville shale wells.

It completed its first Haynesville well in June 2008. Essentially, it had no learning curve: Petrohawk’s first batch of wells tops the list of high-flowing Haynesville powerhouses, coming in at initial-potential rates between 15- and 28 million per day apiece.

“We have been working our own area, and it’s not small,” says Dick Stoneburner, Petrohawk executive vice president and chief operating officer. “There are 30 miles between our farthest wells, and we have seen results improve with each well.” This is supported by the most recent completions that Petrohawk announced in early December, with initial production rates between 21- and 28 million per day.

Petrohawk holds 300,000 net acres in the play. It currently runs 11 horizontal rigs and completes approximately four to five Haynesville wells a month. At year-end 2008, it expected to have 12 to 13 Haynesville wells on production.

The company figures that its acreage contains some 12 Tcf in potential resources. It recently upped its reserve estimates to 6.5 Bcf per well, and recovery potential to 50 to 60 Bcf per section.

“Both production performance and volumetric data support these estimates. The amount of gas in place is astonishing,” says Stoneburner. The notably homogenous Haynesville has a net-to-gross ratio of nearly 100% across more than 4,500 square miles.

Certain Petrohawk strategies differentiate it from other operators. In advance of its horizontal rigs, the company drills the vertical sections of its Haynesville wells with pre-drill rigs. These “spudder” rigs drill to 500 to 600 feet above the Haynesville, set casing and move off. “The program is cost beneficial—our dayrates are less, and the mobilization and demobilization charges are more than offset.”

One drilling concern is bottomhole temperature, which rises to the southeast as the reservoir deepens. “In deeper portions of the play, the industry is approaching limitations with the temperatures associated with getting MWD tools to work,” says Stoneburner. “We’re fortunate in our area that we’re not at temperatures above the specifications of the tools.”

On completions, Petrohawk likes short stages. It has not fractured a well with fewer than nine stages, and most of its wells feature 12-stage fracs. Each stage covers approximately 325 to 350 feet, and takes about 80,000 pounds of 100-mesh and 200,000 pounds of 40/70 premium proppant in slick water. “We pump as little gelled fluid as possible; we don’t go to gel until we have to.” Additionally, the company runs both resin-coated and ceramic proppant.

“We’re quite anxious to get out of our own little comfort area around Elm Grove and Caspiana and prove that we can drill the same kind of wells throughout the play,” he says. “I’m hopeful and optimistic that will be the case.”

In that light, one of the three recently completed wells, which had an initial rate of 28 million per day, was drilled 12 miles south of Elm Grove, and Petrohawk has started wells in Harrison and Shelby counties, Texas. The Harrison County well is a Haynesville test, while the Shelby well is actually a horizontal test in the Bossier shale that lies above the Haynesville. “It appears to have petrophysical properties similar to the Haynesville’s.”

That would be something, if it works. It would add yet another broad target to a region already brimming with opportunity.

Established Player

Some companies with enviable Haynesville positions had the good fortune to hold ArkLaTex leases acquired for shallower objectives. That was the case with Houston-based Goodrich Petroleum Corp. “I would like to tell you that we had a vision the Haynesville was coming, but that would not be accurate,” says Robert Turnham, Goodrich president and chief operating officer. “We liked the area because of its multiple objectives and the repeatability of the plays.”

Goodrich began assembling its position in East Texas and North Louisiana in late 2003. It gathered a package of properties that targeted Cotton Valley and other standard-issue shallow zones. “We were fortunate enough to get in early and put our acreage together,” he says. Indeed, Goodrich’s position in Bethany-Longstreet and Longwood fields, in DeSoto and Caddo parishes, Louisiana, is in the heart of the Haynesville.

Early last year, Chesapeake came calling. The two firms struck a joint-venture deal, in which Chesapeake paid Goodrich $173 million for deep rights on 10,200 net acres in North Louisiana, spread across Bethany-Longstreet and Longwood. Chesapeake, operator of the JV, has two rigs running at present and will add two more by the second quarter.

“Our basis in the acreage is extremely favorable; prior to the JV, our land costs were $350 per acre,” says Turnham. “When we apply Chesapeake’s payment, we actually have a credit of $2,500 per acre.”

In total, Goodrich currently owns 22,000 net Haynesville acres in North Louisiana. It also has a Haynesville venture with Matador Resources on its Central Pine Island project in Caddo Parish, adjacent to Longwood Field. A Haynesville well, operated by Matador, is drilling on that property.

Furthermore, Goodrich expects to spend $75- to $100 million this year in capex on its East Texas holdings—38,500 net acres prospective for Haynesville in Minden and Beckville fields in Panola and Rusk counties.

Goodrich has high hopes: “Of the 10 vertical pilot wells we’ve drilled to date, the best production rates have come from our East Texas wells,” he says. Reasons for this are not straightforward, as the Haynesville is a bit thinner and shallower in East Texas than in Louisiana. Porosities are alike, from 9% to 15%, and gas-in-place calculations also conform. From its westernmost vertical well at Minden, across East Texas and into North Louisiana’s Longwood Field, the Haynesville is strikingly similar.

“Yet, we’ve seen rates as high as 2.6 million cubic feet per day from a vertical well in Minden Field. The highest rate we recorded in North Louisiana was a million a day from a vertical completion,” he says. “Until we can find out differently, we feel just as good about our East Texas acreage as we do about North Louisiana.”

And, the company is pushing down into the Angelina River trend to see if the Haynesville is prospective there. Goodrich recently added a 50% interest in 6,000 acres in Nacogdoches County, and is currently drilling a vertical well to test Haynesville at 14,500 feet on that property. It’s targeting the shale as seen in Trawick Field, where a strong vertical Haynesville completion came in at 3.3 million a day.

“We have almost 42,000 net acres in the Angelina Trend that’s not included in our 60,500 net Haynesville acres,” says Turnham. “It will be a huge addition for us if this area works.”

Vertical wells in the Haynesville run $2.7 million. At mid-year 2008, Goodrich posted average reserve size of 300 million cubic feet for an incremental Haynesville completion below the Cotton Valley sand. Costs for adding the Haynesville tail run $500,000.

“If horizontal wells don’t work in certain areas in the Haynesville, Cotton Valley wells can be deepened to capture Haynesville on 20-acre spacing,” he says. “This offers us the ultimate downside protection.” It’s a fallback option, certainly, but one that may never need to be taken. “The Haynesville reservoir looks so superior. The big question we—and most others—have is the decline rate on the wells.”

East Texas Expansion

Radnor, Pennsylvania-based Penn Virginia Corp. exhilarated Haynesville players when it announced sterling results on its #5-H Fogle in Harrison County, Texas. The stout well was the first to jump the play from North Louisiana into East Texas; it was completed for 8 million cubic feet a day, a rate restricted by the surface facilities.

Penn Virginia had been looking at the Haynesville play (which it prefers to call the Lower Bossier shale) for several years. It had an active Cotton Valley drilling program in East Texas, and drilled rat holes into the top of the overall Bossier section.

“We kept picking up quite a bit of gas on mud logs as we drilled this part of the hole,” says Baird Whitehead, president of Penn Virginia Oil & Gas, the company’s E&P unit. In 2006, as part of its Cotton Valley program, Penn Virginia took 17 vertical Cotton Valley wells down through the Smackover.

It encountered gas shows in most of the Upper and Lower Bossier shales, Haynesville Lime and Smackover in the holes. It started completing, and it tested the Lower Bossier shale in most of the wells in the group. Completion rates on a sustained basis, after fracturing the vertical section, ranged from 100,000 to 300,000 cubic feet per day per well from the Lower Bossier shale.

Based on sidewall-core and advanced-log data and its vertical well results, the company decided the shale would make a good horizontal candidate.

The Fogle absolutely exceeded expectations. “The well has already made half a Bcf, and is at least a 6- to 8-Bcfe well, based on history to date.”

Penn Virginia did not have drilling issues in its first well, which required 16-pound-per-gallon mud in the shale section. But, subsequent tests have been more difficult. “This is a technically challenging play: It’s deep, with high temperatures and high pressures, and well control can be an issue. It can be a bear to drill, although we have made some solid improvements with recent wells.”

The company holds approximately 62,000 acres in the play. Of that total, about 12,000 acres reside in an area of mutual interest that it formed in 2003 with GMX Resources Inc. for Cotton Valley drilling. That AMI extends to the Haynesville, and Penn Virginia plans to drill shale wells within the agreement this year.

To date, it has focused on its 100% acreage. During the past several months, it has drilled wells across its position to test potential. “As of the beginning of December, we had completed five wells and were waiting on completions with a small number of recently drilled wells.”

Results have been announced on three tests, all of which are producing. It currently has three rigs drilling Haynesville wells; the play will command 40% of Penn Virginia’s 2009 budget.

The Lower Bossier wells run $7 million apiece; as costs decline in the service sector, Penn Virginia expects a well could be drilled and completed for less than $6.5 million.

“The Lower Bossier play is huge. There is going to be variability—we think estimated ultimate recoveries may range from four to 10 Bcfe per well, depending on area—but, in general, the economics are strong. We think it’s the most prospective domestic shale play.”

Across its acreage position, based on a conservative 20% recovery of gas in place, Penn Virginia could have net recoveries of 1.5 Tcf or more.

Furthermore, potential exists in the Upper Bossier. “We will drill a horizontal Upper Bossier shale well this year. It’s also overpressured, and appears to have excellent reservoir qualities. And, the Upper Bossier generally overlays the same area as its lower cousin.

“East Texas is just amazing: There’s also potential associated with the Haynesville Lime and Smackover, and deeper ideas yet.”

Right Place, Right Time

A regional firm that has found itself well positioned in the burgeoning shale play is GMX Resources. The Oklahoma City-based company plans to spend 85% of its 2009 and 2010 budgets drilling and completing Haynesville/ Bossier shale horizontals, says Ken L. Kenworthy Jr., president, chief executive and chairman.

GMX was initially a Cotton Valley sand player, but in 2006 it drilled 19 vertical penetrations below the sand into the Bossier/Haynesville shale and into the Smackover. It encountered abundant gas in most of those layers, and was particularly interested in the Lower Bossier/Haynesville that exhibited the most gas and carried the best porosities.

?The firm experimented with different types of completions on its vertical wells, and reached rates as high as 1- to 2 million a day, with steep declines. It took cores and did extensive analysis, including collection of advanced-logging suites. It joined Core Laboratories’ proprietary Haynesville shale-gas study.

??“At the time, we didn’t know how best to develop the reservoir horizontally, so we waited for other, large-cap shale developers to show us the way,” says Kenworthy. GMX eventually turned its focus back to drilling the Cotton Valley sand.

?That all changed when Penn Virginia announced results from its nearby Fogle well, immediately next to GMX’s leasehold.

?“The horizontal play in Caddo Parish was turning up success after success and, when Penn Virginia verified it in Harrison County, Texas—right next to us—that was the confirmation we needed to go in head-first,” says Kenworthy.

?GMX’s quick reaction allowed it to double its acreage position in short order. It now holds 38,455 net Haynesville/Bossier shale acres, and operates 81% of that.

?“It looks like the Haynesville will be two to three times as lucrative as the Cotton Valley,” he says. “Payouts in the Haynesville are measured in months; Cotton Valley sand wells take three years to pay out.”

?Additionally, the Haynesville holds twice as much recoverable gas as the Cotton Valley. GMX estimates it has resource potential of 2 Tcf in the Haynesville/Bossier shales, compared with 1 Tcf in the Cotton Valley sand.

?The company just completed its first Haynesville well, #9-H Callison, in which it holds a 100% interest. It is making 7.7 million cubic feet per day from a 2,200-foot lateral that was stimulated with an eight-stage frac.

GMX’s quick reaction allowed it to double its acreage position in short order. It now holds 38,455 net Haynesville/Bossier shale acres, and operates 81% of that.

??“The Haynesville absolutely has the ability to withstand a low-price environment. It will be the last field standing because the reservoir is that superior.”

?Northern Side

???Southern Star Energy Inc. is a small firm working the northern side of the play in Louisiana. “We’ve now drilled two wells into the Haynesville and, the more I learn, the more tickled I am with what I see,” says David Gibbs, Southern Star president and chief executive officer.

???The company was formed two years ago to chase North Louisiana projects. Initially, it targeted Cotton Valley; to date Southern Star has drilled seven such wells. It holds 5,400 contiguous net acres in Louisiana’s Bossier Parish, with partners Ramshorn Investment and Dynamic Resources. Southern Star holds 40% of the venture and operates.

Its first Haynesville well, #17-2 Atkins-Lincoln, was designed as a vertical hole set up for resource assessment. “We are very happy with the section we encountered in the #17-2 well,” says Gibbs. “We had strong gas shows and very good porosities throughout the interval.”

????Moreover, reservoir thickness is outstanding: The well encountered some 390 feet of prospective section. “This well confirmed the presence of porous Haynesville shale on our acreage. It’s changed our perception of the play’s extent, and the potential of our position.”

?Southern Star has temporarily suspended the well; pending the results of its evaluation, it will either complete it as a vertical producer or drill a lateral into the shale. To enhance its understanding of the play, the company also joined Core Labs’ proprietary Haynesville study. Southern Star took 180 feet of whole core in the upper shale zone and sidewall core in the lower interval.

?“We had a lot of gas coming out of the well, but we were able to keep it under control, and we had excellent hole stability.”

?A second Haynesville well, #20-1 A.S. Burt, about 1.5 miles southwest of the initial test, has further confirmed the presence of Haynesville potential on the company’s acreage. The Burt well encountered a slightly thinner gross interval (312 feet) but improved porosity and resistivity. In its current 10-well program, Southern Star expects to devote five to six wells to test the shale; the remainder will develop Cotton Valley targets.

?“At this stage of the game, we are drilling vertical holes and leaving wellbore geometry that allows us to drill horizontals. If we go horizontal, we’ll bring in a different rig for the lateral portions.”

?The cost difference between horizontal and vertical Haynesville wells is considerable. In its area, a massively fractured vertical Haynesville can be completed for $3.9 million; a horizontal runs $8 million.

??“We’re working to decide the best approach going forward. We’re poised for some real growth.”

Robust Economics

???So that’s the Haynesville: Good news abounds. It offers strong wells, huge extent and onshore operations in an established corner of The Patch.

??Enormous amounts of capital continue to pour into the Haynesville, and a growing number of companies have taken stakes. In addition to companies mentioned above, Berry Petroleum Co., Bridas Energy, Cabot Oil & Gas, Camterra Resources, Clayton Williams, Comstock Oil & Gas, Cubic Energy Inc., Devon Energy Corp., EnCana Corp., Exco Resources Inc., Fossil Operating, J-W Operating, Nadel & Gussman, Questar Corp. and Shell Oil work the play.

??In these difficult times, even if smaller players or distressed companies are bought out, the buyers will remain committed to Haynesville development.

?The leases are expected to be drilled—as the economics are robust. “In our estimate, returns on a midpoint Haynesville well are on par with returns from a core-area Barnett well,” say Robert Clarke, Houston-based lead analyst, U.S. Lower 48, and Hill Vaden, Gulf Coast analyst, for energy-research and -consulting group Wood Mackenzie. Midpoint Haynesville returns do not top the nations’ premier onshore play—the Deep Bossier in East Texas’ Amoruso Field—but are superior to returns from Cotton Valley and Wilcox.

???Breakeven prices—those that deliver a 10% rate of return—for the Haynesville fall around $5 per thousand cubic feet (at Henry Hub). The range is between $4 and $6.50.

And, that range is fluid. As gas prices drop, it’s anticipated that costs will drop. “We’re already seeing costs come down, and that will subsequently drive down the breakeven point.”

???In other, more-established shale plays, returns improved over time as operators became more efficient and tailored drilling and completion techniques to the specifics of each reservoir. “What’s striking is the relative immaturity of the Haynesville. There’s significant upside, should wells improve,” says Clarke. “Returns are now very good, and are likely to get even better.”