ECA VP of Eastern Operations, Kyle Mork, Quoted in Marcellus Development Article

Marcellus and Haynesville Grab Industry's Attention as Gas Shale Giants

The American Oil & Gas Reporter
March 2010

By Del Torkelson
PITTSBURGH–Development work in the Marcellus and Haynesville shales has been under way only for a couple years, but early returns from this “third wave” of U.S. shale plays already have elevated the two unconventional gas goliaths into a league of their own and made them the envy of the western world.
Indeed, if the Barnett Shale blazed the unconventional natural gas trail, the Marcellus and Haynesville are paving a thoroughfare. Die-hard wildcatters and damn-the-torpedoes financiers alike have changed their time-honored preferences from fine-tuned, but relatively low-percentage field development and exploratory drilling to orchestrating the repeatable financial rewards of shale gas “manufacturing” processes.
After the Barnett established the game-changing template for coaxing commercial quantities of gas from shale, operators began to transplant look-alike horizontal drilling and hydraulic fracturing concepts to a second generation of plays, namely the Fayetteville and Woodford shales. Even as they labor to engineer ever-better drilling and completion techniques, companies are relishing the repeatability and world-class productivity of shale plays. As Bob Dylan declared in his 1960s anthem, “The times, they are a-changing.”
That change is evident in any analysis of the road ahead in natural gas supply and the rapidly expanding role of unconventional resources. For example:
•    According to figures obtained from Baker Hughes and Louisiana Department of Natural Resources Secretary Scott Angelle, more than 11 percent of the 891 rigs drilling for gas in the United States in early February could be found in the Haynesville’s home base of Northwest Louisiana, with DeSoto Parish alone accounting for 5 percent of all U.S. gas drilling.
•    Texas Keystone Director of Geology Gregory Wrightstone cites nine expert opinions since 2002 that give progressively larger estimates for recoverable Marcellus reserves. The two most recent foresee exceeding 500 trillion cubic feet, an output sufficient to rank second in the world.
While one published report has pegged the Marcellus as covering more land than Greece, the Haynesville Shale appears thus far limited to a much smaller hot spot in Northwest Louisiana, East Texas and North Arkansas. Nevertheless, initial results demonstrate that ingenious operators are transforming the Haynesville into a true industry giant in terms of its potential.
According to Louisiana Oil & Gas Association Director of North Louisiana Jodee Bruyninckx, as of October 2008, 174 units had been permitted for the Haynesville Shale and it had 13 producing wells. “Fast-forward 15 months to January 2010, and there are more than 1,400 permitted shale units and 318 producing wells,” she reveals. “We all knew the Haynesville had to be good, but we have been pleasantly surprised to find several wells producing at absolutely astounding levels.”
Core Marcellus Areas
Although the industry did not begin drilling Marcellus Shale wells in earnest until the past couple years, Kyle Mork, vice president of eastern operations for Energy Corporation of America, recalls folks had been murmuring about the formation for much longer. “By 2007, the Marcellus was the industry’s worst kept secret,” he quips. “People were talking about it, although not publicly.”
Dana Johnson, president of Enerplus USA, remembers that atmosphere. The scattered information Enerplus had gleaned aroused the company’s interest, he allows, but specifics remained hard to come by. As more data trickled out, Enerplus made its move. “It was key for us to be able to assimilate public data with what we could learn on the street,” he describes. “We managed to extrapolate that into a pretty sizable joint venture acquisition of Marcellus Shale interests.”
Mork recalls that Marcellus drilling truly got off the ground in 2008. “But there was still a lot of debate about whether it would be a vertical or horizontal play,” he notes. “In 2009, it really took off as people got their hands around how to do it. “
Wrightstone says discussions of the Marcellus tend to identify two core areas. “People talk about a core area in Southwest Pennsylvania that includes the counties of Greene, Fayette, Washington and Westmoreland, and extends into Marshall and Wetzel Counties in northern West Virginia,” he describes. “There is another core area that would include the Southern Tier of New York and Northeast Pennsylvania, southwest into Centre County, Pa.”
Chris Doyle, general manager of Anadarko Petroleum Corporation’s Marcellus operations, reports, “Our 700,000-plus gross acres give us access to that northeast core. We really are excited about what we know it will be able to deliver.”
Wrightstone explains that both of those core areas lie within the play’s extensive high-pressure portion, the lion’s share of which is in Pennsylvania. Although northern West Virginia also contains some high-pressured Marcellus, most of the Mountain State’s Marcellus wells lie outside that window, he says.
“Lots of wells in southern and south-central West Virginia are technically Marcellus producers, but it is not economic to drill them for the Marcellus Shale alone,” Wrightstone holds. “Companies are commingling them with shallower production and still getting decent wells, but no one should expect high-volume, high-reserve wells outside the high-pressure area.”
Mork says ECA has properties in both the underpressured and high-pressure portions, and notes that the company’s Marcellus wells in southern West Virginia are 4,000-4,500 feet deep, while those in southwestern Pennsylvania reach 8,000-8,200 feet. “It is an entirely different play,” he describes. “In the southern part of the Marcellus, we are drilling on air and fracturing with nitrogen. In the northern portion, we are drilling overpressured with much bigger rigs, fairly heavy mud weights, and slick-water completions. The entire approach changes drastically.”
Expectations And Reality
Surface considerations influence methods used in the play. The Appalachian Basin’s frequently forested and hilly-to-mountainous topography can complicate the logistics of transporting large equipment and building locations sufficient to complete horizontal Marcellus wells.
Wrightstone says companies are getting creative in how they address those considerations. “They are going to centrally located ponds and water-holding facilities,” he reports. “They are drilling as many as eight wells from the same pad, and a lot of companies are recycling fracture flow-back water.”
Doyle says Anadarko embraces practices that minimize surface footprint and hopes that doing so demonstrates to the public that development can coexist with environmental stewardship.
“What will unlock this play in Pennsylvania is a continued effort between the industry and the commonwealth to communicate and establish best practices,” he reflects. “I think the industry can find the best technological solutions, but it really is going to require engaging regulatory bodies and the public in a cooperative effort for the industry to deliver the benefits we know it can.”
Kenneth Komoroski, a spokesman for Cabot Oil & Gas Corp., says the Marcellus is on the verge of delivering those benefits. “In the play’s earliest stages, a lot of residents and business leaders were excited,” he relates. “Of course, a lot of lessors were not familiar with the process, and so some expectations were ahead of reality. Mineral owners were anxious to see the benefits of the deals they signed, but the industry had to drill the wells and get the infrastructure on line. People saw trucks on the roads, equipment moving through towns and flares in the night sky, but they were not seeing revenue. Now those expectations are starting to be realized.”
Nevertheless, Wrightstone cites plenty of remaining issues, including the structurally complex areas being drilled east of the play’s core areas and the best approaches for each part of the play.
“Many people are moving toward 3,500-5,500 feet as the optimum lateral lengths, but one company I know is planning wells to extend to 10,000 feet,” he mentions. “There is a large area in Central Pennsylvania with lower porosity and permeability. Will that be economic? As you go north and west into Pennsylvania and New York, the play thins, gets shallower and becomes less thermally mature. What are the play’s northern and northwestern boundaries?”
Hello Haynesville
The Haynesville’s potential as a top-echelon U.S. shale play appeared not to be common industry knowledge before March 2008, when impressive results announced by Chesapeake Energy suddenly illuminated the formation’s possibilities to the wider industry. Nevertheless, a couple operators who already were active in Northwest Louisiana and East Texas had caught hints that something was in the works.
Goodrich Petroleum Corp. President and Chief Operating Officer Robert Turnham remembers encountering one early sign signifying the changes in store when his company’s routine $350 an acre bid for some state leases was topped by a bid 10 times greater. “That was when we knew something was up,” he recounts. “They obviously were chasing something different from the shallow objectives that interested us. We did some more investigative work and found some vertical wells drilled deep into what we thought was the Smackover.”
A pair of companies with long histories intertwined throughout the ArkLaTex region are Heritage Energy and Camterra Resources, which for years have synchronized strategies and partnered on most projects in the region. Kevin Byram, a geologist and co-owner of Heritage, says that after he and his colleagues deduced the Haynesville was an objective in late 2007, the partners decided to extend a Cotton Valley well into the Haynesville and log it. “We were shocked,” he admits. “We knew at that moment there was a lot of gas in place.”
Heritage and Camterra targeted the Haynesville with a well in January 2008, elaborates John Kinnebrew, a landman and Heritage co-owner. “Was it exciting? Absolutely,” he states. “Was it also painful, stressful and expensive? Absolutely.”
As it became apparent the Haynesville Shale was on its way to becoming the country’s next big shale play, many of the area’s longstanding operators saw their lease values skyrocket. Turnham acknowledges that Goodrich was more than happy to find itself sitting atop a strong Haynesville acreage position.
“Better lucky than smart,” he laughs. “But we were smart enough to put ourselves in position to stumble into new plays. Before 2003, we were primarily a South Louisiana player, and even our North Louisiana drilling focused on structural plays, and buying and rejuvenating old fields. East Texas and North Louisiana are renowned as a place to find gas where it already has been found. After you think you have verified everything that can produce, you find something a little deeper or technology makes something else economic.”
In fact, notes Paul Sander, vice president of the Mid-Continent business unit for EnCana’s USA division, many Haynesville producers already are aware of a likely follow-up target. “Our land position is well-suited for both the Haynesville and the Bossier Shale because we were looking at the Bossier first,” he observes. “We will continue to test the Bossier, which is a similar package around 500 feet shallower than the Haynesville.”
Camterra Chief Executive Zach Carlile says Heritage and Camterra also hold leases with both Haynesville and Bossier potential. “We drilled a vertical test and have seen some Bossier logs,” he relates. “But it really needs to be tested horizontally.”
Even so, Byram is quick to add, the vertical wells are encouraging. “We perforated and fractured it, and it flowed gas not much different from a Haynesville Shale test in a straight hole,” he describes. “We have mud log shows and log analyses for the Bossier Shale, but with the Haynesville wells we need to drill we are not going to drill into it any time soon.”
Drilling Deadline
Most other Haynesville players also are delaying Bossier activity because of provisions in the majority of Haynesville leases written after the play took off. “We have focused on the Haynesville because if we drill a Haynesville well, we can hold the mineral rights to it and the Bossier,” Sander explains, adding that those rights often extend to the deepest horizon drilled.
In fact, Bruyninckx says, one of the toughest tests most Haynesville operators must pass requires them to meet their leases’ three-year terms. “These companies are going to have to drill a lot of wells to hold their hundreds of thousands of acres,” she observes. “Accessing enough rigs, as well as permitting and construction lag times, will make it difficult to drill fast enough.”
LOGA recognized that such a swift development schedule required great care to minimize disrupting area residents, Bruyninckx says, so in September 2008, the association pulled together a group of producers representing more than 80 percent of Haynesville acreage to anticipate and address shale issues. “Representatives from the vast majority of Haynesville companies meet at least once a month,” she reports. “They have been competing for leases, but they have come to trust one another because it is best for their companies, the industry and the community.”
A key issue the committee tackled immediately, she says, examined water supplies for hydraulic fracturing. “It often takes 3 million-4 million gallons to frac other shales,” Bruyninckx elaborates. “It takes between 5 million and 7 million gallons to fracture a Haynesville well. Our companies’ water experts built a very diverse water-sourcing portfolio that keeps the use of groundwater to a minimum.”
Another set of hurdles associated with the Haynesville deals with its high pressures and temperatures. Sander predicts the HP/HT environment will prove even more extreme as the play evolves. “We are going to see temperatures up to 400 degrees in the next 6-12 months,” he forecasts. “There appears to be a pretty strong correlation between depth and temperature, so the deeper you go, the more you challenge your tools’ temperature limitations.”
Sander says EnCana has worked to protect tools such as measurement-while-drilling equipment with mud circulation. “We also are working with service companies to build the assemblies so they vibrate less, because the combination of vibration and temperature causes issues,” he reports. “Overall reliability has increased tremendously.”
Despite the high demands associated with drilling and completion, Turnham emphasizes that Haynesville wells have proven simple to operate. “Once the well is producing, its lease operating expense is much lower than that of our legacy assets,” he imparts. “These wells produce very little saltwater, and the gas has enough pressure to flow without compression. Our lease operating expense initially is as low as $0.15 an Mcf. Historically, our legacy assets have been at about $1.25.”
Another Try
Although its first foray into the Marcellus Shale came decades before his time at the company, Mork may well have wondered if ECA’s second go at targeting the formation nevertheless qualified as déjà vu. He says the company partnered with the U.S. Department of Energy on a Marcellus project in the late 1970s that “did everything wrong,” and ultimately proved a dead end. “People have known for a long time there is a lot of natural gas in the Marcellus Shale,” he notes. “All those wells produced a little gas, but we did not have the ability to get out enough.”
Fast forward to 2005, and ECA was among the companies that wondered if the Marcellus had ripened into an economic producing horizon. And yet, Mork acknowledges, as the company made some early attempts to again drill to the Marcellus, aspects of the experience harkened back to that ill-fated ’70s experiment. “It is almost comical,” he muses. “Whether it was the Marcellus wells in the ’70s or the early wells we tested in this drilling program, we thought pumping 100,000 pounds of sand and maybe 5,000 barrels of water was a big completion.”
ECA now pumps as much as 4 million pounds of sand and 100,000 barrels of water to stimulate its horizontal Marcellus wells, Mork details. “We had very little understanding early on about the scale and complexity of these wells,” he acknowledges. “I think that was the case for the entire industry.”
Mork recalls that one of ECA’s first horizontal Marcellus wells in Greene County, Pa., ended with a only a couple hundred feet of effective lateral and two frac stages. But the well produced “good enough that we started realizing what could happen with a longer lateral and more stages,” he says.
And while ECA has drilled 160 wells into the Marcellus, 25 of which are horizontal, Mork suspects the play’s progression could one day make the techniques of early 2010 appear similarly outmoded. “There are going to be breakthroughs and lessons that will make what the industry is doing now seem as quaint as our efforts in the ‘70s seem to us today,” he predicts. “We certainly like the results we are getting now, but other shale plays have seen continued improvements as people learn more.”
Appetite For Acreage
Mork acknowledges that ECA’s longstanding commitment to never relinquishing mineral leases made an incursion into the Marcellus almost inevitable. “We have about 1 million acres in the Appalachian Basin, and the majority of that has Marcellus Shale potential,” he reports. “ECA has been acquiring acreage, properties and companies since its founding. We have sold well bores, but we do not sell the surrounding acreage.”
Mork estimates the company has picked up 15-20 percent of its prospective Marcellus acreage since 2005, but the rest came before the modern Marcellus era. “We thought it made sense to hold onto the acreage since there likely were deeper plays or ones for which the industry had not yet cracked the code,” he says.
More than 80 percent of that acreage is held by production, which Mork says gives ECA the advantage of drilling where and when it thinks best. “Even our undeveloped acreage can be held with relatively few wells,” he reveals. “We can take a more measured approach.”
Mork reported in early February that the company probably would add a second rig in Greene County, which was the company’s primary near-term Marcellus focus. “We also have big acreage positions in Central Pennsylvania and Central West Virginia, and I think we will start to further test and delineate that acreage,” he adds. “We want to start in the best areas where we have the greatest understanding and gradually build on them.”
ECA has learned a lot while drilling more than two dozen horizontal Marcellus laterals that range in length from 2,000 to 4,000 feet, Mork says, but it also has a lot to learn. “We certainly see some value in maximizing lateral length, but we also know there may be a point of diminishing returns,” he suggests. “A lot depends on structural features. We are doing a lot of seismic work because we want a good picture of the subsurface to know how to place the laterals.”
Multistage stimulation is another aspect with which ECA is experimenting, Mork acknowledges. “We are somewhere between 250 and 500 feet of lateral for each frac stage,” he reports.
Even some of the underpressured portion, including parts of West Virginia, may benefit from horizontal drilling, Mork continues. “We drilled a company-record 4,000 foot lateral in the underpressured part, fractured 14 stages and really liked the results,” he describes.
Prime Location
Although Anadarko holds a significant amount of Marcellus acreage, the company’s general manager for the play emphasizes quality over quantity. “Nearly all our acreage is in the fairway in the heart of the Marcellus Shale,” Doyle reports. “This is prime acreage.”
Most of those acres are in Pennsylvania’s Centre, Clinton, Lycoming, Tioga, Bradford, Sullivan and Potter counties, he details. A mid-February announcement unveiled a key source for exploiting that acreage position when Anadarko reported it had reached a joint venture agreement with Mitsui E&P USA LLC.
Anadarko Chairman and CEO Jim Hackett expresses the company’s affinity for its new Marcellus partner. “This transaction reflects the significant value of Anadarko’s fairway position, which has a gross unrisked resource potential of more than 30 Tcf of natural gas and spans more than 715,000 gross acres,” he describes. “We continue to ramp up our activities in the Marcellus and anticipate drilling more than 4,500 wells in the coming years.”
Doyle upholds the quality of the company’s acreage. “Any structure map will show Anadarko has access to acreage potentially deeper than some other parts of the play,” he allows. “That would tend to indicate higher pressures, which would suggest better wells. We are extremely happy with where we are in the basin.”
According to Doyle, while most Marcellus players are averaging 3,500-5,000 foot laterals, Anadarko is stretching those limits. “We are going to 6,000 feet and even have a couple 7,000-foot laterals,” he reveals. “On a 3,500-foot lateral, most companies probably go with a five- to seven-stage completion, but we are playing around with 10-12 stages. We are encouraged by what we see.”
Even as Anadarko’s laterals go longer, Doyle says the company also strives to shorten average drilling and completion times. “Late last year, I would have said it took 30-40 days, but our drilling department sets records every month,” he boasts. “Our last well, from spud to rig release, was 23 days. I think we will continue to drive down cycle times as we drill more wells.”
Responsible Operator
Anadarko began to accelerate its Marcellus program early last summer, Doyle says, shifting almost exclusively to drilling horizontals from pads to minimize cycle times and footprints. “The Marcellus Shale is the type of environmentally challenging play in a strict regulatory environment that really leverages the strengths and skill sets Anadarko has built,” he holds.
That entails operating large developments with an emphasis on environmental responsibility, Doyle says. “Early on, Anadarko was excited that the Marcellus would play into its strengths,” he reveals. “The company thought it would be a great fit.”
Anadarko’s major focus for 2010, he says, is to better understand the company’s prospects. “We have drilled more than 50 wells, both operated and nonoperated,” Doyle reports. “We exited 2009 with three or four operated rigs and 10 nonoperated rigs. By the end of 2010, we probably will be running five to seven operated and 15 nonoperated rigs.”
Doyle points out that shale veteran Chesapeake Energy Corp. operates the north portion of the companies’ shared Marcellus acreage, with Anadarko operating the southern side. “Chesapeake has led some very large gas resource plays,” he reflects. “Anadarko partners with Chesapeake in other parts of North America, and we are comfortable working with the company.”
In addition, Anadarko’s mid-February, $1.4 billion joint-venture agreement made Mitsui a 32.5 percent partner in Anadarko’s Marcellus assets. Anadarko explains Mitsui will earn 100,000 net acres in exchange for funding 100 percent of Anadarko’s share of development costs in 2010, and 90 percent thereafter. The deal provides Mitsui the opportunity to purchase 32.5 percent of Anadarko’s existing wells and additional acreage acquisitions.
“We have successfully partnered with Mitsui in other parts of the world and look forward to working with them and our other partners in the Marcellus,” Hackett states.
Susquehanna Focus
Cabot Oil & Gas Corp. spokesman Ken Komoroski acknowledges it is difficult to pinpoint a precise time at which the company’s plans for the Marcellus Shale switched from “maybe someday” to “full speed ahead.” Instead of a bolt from the blue, he says, the company’s epiphany was more gradual.
A couple of signposts along the journey occurred when Cabot drilled one vertical well to the Marcellus in 2006 and another in 2007, he recalls. “Both had promising results,” Komoroski describes.
Eventually, he says, the company decided its strong acreage position in Northeast Pennsylvania made it logical to pursue a Marcellus drilling program. “The shale has considerable thickness in Susquehanna County, and our geologic reports indicate it has excellent productive potential,” Komoroski relates.
According to company releases, Cabot has accumulated more than 170,000 gross acres in Northeast Pennsylvania. Cabot Chairman, President and CEO Dan Dinges says, “From this position, we are expanding our efforts in 2010 to 73 horizontal wells and 10 vertical wells. This is more than a doubling of our effort, and will account for two-thirds of our 2010 investment program.”
By the latter part of 2009, Cabot said it had nine producing horizontal wells–three of which had yielded more than 1 billion cubic feet of gas–and was on schedule to bring its Marcellus well count to 30. At the end of October, Cabot indicated its 24-hour initial production rates ranged between 4.6 MMcf/d and 11.5 MMcf/d, with 30-day rates ranging from 3.5 MMcf/d to 10.9 MMcf/d.
Dinges emphasizes that the company’s Marcellus output has grown exponentially from October 2008 to the same month in 2009: from about 5 MMcf/d to more than 50 MMcf/d.
Cabot set out on a Marcellus drilling program with a handful of wells in 2008 and stayed the course toward more development in 2009, despite choppy commodity markets, Komoroski notes. “We stuck with the plan,” he emphasizes. “In 2009, the play remained in its early phases and we simply stuck with the plan in a belief that gas prices would rebound.”
A New Model
One of the newest Marcellus entrants is a company for which entering the play is merely one aspect of a much broader companywide transformation. Dana Johnson, president of Enerplus USA, explains that the company’s Canadian parent is an energy income trust on the path to converting to a corporation.
Although Enerplus was the first such royalty trust, he reports, the Canadian government’s decision a few years ago to remove the nontaxable provisions for trusts prompted the company to adjust its business model. “Enerplus wants to continue as an income producer, but add a growth component to the business as well,” he describes. “It is entering an increasing number of select, earlier-stage resource plays such as the Marcellus Shale.”
The doorway, Johnson continues, was opened by a September 2009 transaction that made it a joint venture partner with Chief Oil & Gas. “We looked at a number of deals and Chief’s really emerged as right sized,” he recounts. “We knew a few of the team  members at Chief and the company had an excellent track record in the Barnett Shale.”
Another draw, Johnson continues, was Chief’s Marcellus leasehold, which spread from the Northeast Pennsylvania counties of Susquehanna, Lycoming and Bradford south across the state line into Marshall County, W.V.
Chief had drilled 30 Marcellus wells at the time the JV deal was closed, Johnson says, and the partners have since set about fitting together complementary pieces, with Enerplus sending some of its select technical staff to work on behalf of Chief in its Wexford, Pa. office.
Johnson says the JV has drilled 15 wells with the four rigs it has working the play. With plans to add a fifth rig at some point in 2010, he says the companies would like to drill 50-60 gross Marcellus Shale wells this year.
Nevertheless, Johnson acknowledges that the JV does not exhaust Enerplus’ ambitions for the play. When the parent company was scanning the landscape of North American resource plays, the Marcellus’ proximity to markets and gas volumes placed it among the choicest plays. “Eventually, if the economics work and the deal market is willing, we will acquire an operated position,” he reveals. “Operating allows a company more control over its destiny, and we believe we can compete in the Marcellus.”
Clearly, he concludes, evolving technological capabilities are creating inroads to optimize drilling and improve fracturing treatments. “I think 3-D seismic will have an increasing role in Marcellus Shale development,” Johnson says. “It does not share some of the geohazards of the Barnett Shale, but in laying out topography and efficient development plans, 3-D will have a role.”
Deluxe Drilling
As North America’s third-largest natural gas producer, 90 percent of which is from unconventional targets, Sander says EnCana has demonstrated a knack for getting involved in hot shale plays. The Haynesville is yet another case in point.
Sander notes the company entered the Haynesville Shale in 2005, when it was pursuing a Gulf Coast Jurassic trend. “We were looking for Bossier Sand and we drilled our first test wells in early 2006,” he recounts. “We saw a really great-looking shale in the Haynesville.”
Sander says EnCana shifted its attention to the Haynesville, did some production testing, and “was pretty encouraged by our results. By early 2006, we recognized that this was a big discovery.”
While EnCana already had accumulated some Haynesville acreage, Sander says the company increased its leasing activity and obtained a position that eventually grew to 435,000 net acres. The company also began to consider potential partners. “After we drilled the initial vertical wells, we partnered with Shell on our Louisiana position,” he reports. “That helped to move our program forward.”
EnCana’s first horizontal Haynesville well came on line in spring 2008, Sander says, and horizontals constitute all but a handful of the company’s 100 gross Haynesville wells. He adds that EnCana plans to devote $750 million to drilling 140-160 wells during 2010. “We are operating 22 rigs, 16.5 net,” Sander reports. “I think we will look at the possibility of increasing the program as we get more comfortable.”
He describes EnCana’s Haynesville strategy as focused on maintaining the company’s land position. “We have identified 165,000 core acres, and we are going to hold those units,” he explains. “We will be testing the rest of our leased positions to grow.”
Sander says EnCana also is trying to determine the optimum spacing for field development in an effort to eventually initiate what he calls “gas factory work” through pad drilling. “Right now unit spacing is 640 acres. We put a pad on a unit and drill our laterals predominantly north-to-south,” he details. “Our lengths are limited to 4,200-4,600 feet by the current unit spacing.”
Creating Efficiencies
EnCana reports its Haynesville drilling, completion and transportation costs averaged $8.8 million a well in the fourth quarter of fiscal 2009, a figure the company says it wants to trim to $8.0 million-$8.5 million. Its drilling design, which Sander says already has brought EnCana’s costs down 40 percent from its initial Haynesville wells, averages 50 days from spud to spud with a focus on quick rig movement, built-for-purpose bits, and faster drilling motors. However, EnCana indicates its long-term drilling target is less than 35 days, which it hopes to attain by using 3-D seismic, preset surface casing, and water-based fluids to drill laterals.
“We have been using newer rigs that are more fit for purpose to the Haynesville,” Sander relates. “Almost all of them include automated pipe handling systems and bigger pumps. They are quick moving, skiddable, or both. Shifting from oil-based to water-based muds looks very promising for drilling faster and lowering costs.
“We also are continuing to push the limits on managed-pressure drilling,” Sander continues. “If we can drill without so much fluid column or mud weight, we can drill faster, especially in the curve and lateral sections. Understanding how to drill these wells faster will allow us to get the right rig, and optimize our mud and bits.”
On the completion side, Sander says EnCana is pumping 10-14 stages at a rate of 70-75 barrels a minute as it works to stimulate a greater volume of rock by pumping more proppant and increasing the number of perforations in a cluster from four to five.
“It is almost an open-hole completion,” he reports. “We have learned to pump more proppant in the Haynesville Shale because the rock is softer and not as brittle as the Barnett. The more sand we pump per linear foot, the better well we get.”
Although they could flow more, Sander says EnCana limits initial production rates to 23 MMcf/d on 22⁄64- or 24⁄64-inch chokes. Many of EnCana’s recent Haynesville wells, he says, maintain 15 MMcf/d for 30 days, consistent with projections. “We are seeing wells that are stronger initially and last longer,” he reveals. “The first wells we drilled in what we consider the core area were in the 2.0 Bcf-3.0 Bcf range. Our wells in the same area now are looking at recovering 7.5 Bcf.”
As for efforts to reduce completion costs, Sander says a key focus includes trimming hydraulic horsepower for fracturing operations. “We have decided to pay a little more for steel and use 51⁄2 inch instead of 5 inch casing,” he notes. “That will bring down pressures at the surface by 1,000 pounds and reduce our overall horsepower.”
Under Pressure, Big Risks
What if opportunity knocked, but one hesitated to answer because it was accompanied by the less-welcome acquaintances known as pressure and risk?
That was the conundrum faced by the principals of Camterra Resources and Heritage Energy in early 2008 as Carlile, Kinnebrew and Byram shared the role of an oil patch Hamlet and pondered whether to play or not to play in the still relatively unknown Haynesville Shale.
Carlile recalls brooding over the possibility at the North American Prospect Expo in February 2008 as he was preparing to drive one of Camterra’s owners, Michael Merriman, from the expo to the airport. “He said I looked stress ,” Carlile chuckles. “News of the Haynesville barely had started to percolate, so I replied that I really needed to talk to Kinnebrew about it.”
As two outfits with a combined employee count below 35, companies as small as Camterra and Heritage knew they could only participate in a major shale play if they entered early, Carlile says. “I knew we needed a leasing plan,” he says, “or our companies would not be able to keep up with the dollars.”
According to Kinnebrew, “No one knew the Haynesville was so productive,” he insists. “As a matter of fact, we had asked for (but were denied) a farm-out of the same unit that initially established the Haynesville Shale play in Caddo Parish. Truthfully, we probably would not have known what to do with the Haynesville, but we watched the initial wells as they were drilled, completed and–most importantly–subsequently produced.”
Carlile says Heritage and Camterra’s initial Haynesville acreage was held by Cotton Valley and Hosston production in the Elm Grove Field. “We started in Bossier Parrish, La., and then in early 1999-2000 got into West Elm Grove in Caddo Parrish. Then we leased into northern DeSoto Parish and further into the west part of Caddo Parrish as we developed our Cotton Valley idea . . . which became a Haynesville Shale idea.”
The companies were enlarging their leasehold over northern DeSoto and southern Caddo parishes in spring 2008 when the Haynesville play suddenly took off. “Around the time everything broke, we went on a speculative lease play, bought acreage in North Louisiana and East Texas, and flipped it,” Kinnebrew describes. “That was to help finance a drilling program on the rest of our Haynesville acreage.”
While liquidating suddenly valuable acreage made sense to many of his colleagues in the industry, Byram says, many of them seemed incredulous that companies as small as Camterra and Heritage intended to actually participate in the play. “Most people think we are crazy,” he admits. “We have done well, but we do not have market capitalization of several billion dollars nor the ability to raise money at the drop of a hat. The money we spend is our own.”
Growth Engine
As of early February, Carlile said the partnership had drilled several vertical Haynesville wells and was in the process of drilling its eighth horizontal well. He indicates the company plans to drill 10 horizontal Haynesville wells in 2010.
That process was assisted by taking the companies’ Cotton Valley drilling program horizontal in 2007, according to Kinnebrew. Although the Cotton Valley typically is 2,000 feet shallower than the Hayneville, he says, it seemed logical to trade that program for one in the Haynesville.
That preparation was valuable, Carlile allows, but experience soon offered the companies an expensive tutorial on differences between tight gas sands and shale. “An expensive Cotton Valley well might cost $2.5 million,” he details. “Our horizontal learning well in the Haynesville cost more than $20 million. We paid about $10 million in ‘dumb taxes.’”
Although Heritage and Camterra have since sliced more than half that cost, Byram says even the smoothest Haynesville horizontal drilling and completion operations still total between $7.5 million and $9.5 million. “That requires making very good decisions,” he reflects. “These wells cost $100,000 a day whether you are drilling 500 feet of hole or dealing with stuck pipe.”
But while costs have ballooned, Carlile notes that so, too, has the companies’ room for growth. Camterra’s and Heritage’s cumulative production stood at 50 million gross cubic feet a day before the partners sold more than 200 Cotton Valley wells in early 2008. “We were down to 10 MMcf/d,” he estimates. “With six Haynesville Shale wells now on line we already are nearly at 40 MMcf/d. The rate at which this play can grow our companies’ production is amazing.”
With that in mind, Carlile, Byram and Kinnebrew agree that Heritage and Camterra emphasize a well’s estimated ultimate recovery over its initial production. “We do not have to impress anyone other than ourselves,” they suggest.
“Our first goal is to make the highest EUR possible. We are of the opinion that producing Haynesville wells at the highest-possible IP reduces EUR by dropping the reservoir pressure too rapidly, thereby damaging the well bore and the formation,” Carlile says. “Since our second well, we have pinched back to between a 13⁄64-and 15⁄64-inch choke. They are coming on between 8 MMcf/d and 9 MMcf/d. There is no doubt we could bring them on at 15 MMcf/d, but we think that could be the difference between 4 Bcf or 6 Bcf-7 Bcf EUR.”
Camterra and Heritage also are willing to pay more for higher-end completions, which typically include 12 frac stages for a 4,000 foot-lateral, Byram notes. “We use a cross-linked gel frac with a resin-coated sand and a ceramic proppant,” he says. “We think taking the long view makes sense.”
Carlile says the partners’ horizontal Haynesville wells average 38 days from spud to total depth, although the companies have drilled wells in as few as 32 days. “With practice and technology, we have a reasonable hope to eventually bring that down,” he reports. “The goal is 29 days.”
Shale Entry
For Goodrich Petroleum Corp., the pregame warm-up for playing in the Haynesville Shale came with the company’s 2003 decision to go after a smaller-scale play. According to Turnham, stronger natural gas prices and fracturing innovations made some East Texas horizons worth another look. “We were targeting the Cotton Valley, the Travis Peak and the James Lime,” he recounts. “We put a block together, tested it, and the new frac technique worked exactly as planned.”
Goodrich certainly had not ignored the industry’s burgeoning shale play revolution, Turnham indicates, and as a public company it had appreciated the demonstrable value of a repeatable drilling program. Nevertheless, he says, the company watched plays such as the Barnett from the sidelines while it established its own sort of resource play by acquiring more than 40,000 acres in East Texas.
“We felt we would be getting into the game a little late in the Barnett, but the same theory applies with the need to stimulate tight gas sands,” Turnham relates. “We saw the same type of opportunity targeting shallow objectives in Caddo and DeSoto parishes in North Louisiana. We drilled more than 400 shallow vertical wells to the Cotton Valley.”
After news broke of Chesapeake’s Haynesville success in spring 2008, he says Goodrich began to delineate its position and establish the quality of its acreage by drilling vertical wells and taking core analyses. However, Turnham says, Goodrich immediately faced a steep learning curve as to how to best drill and complete horizontal Haynesville wells.
One way the company scaled that curve was by selling Chesapeake 10,000 acres for $175 million, Turnham says. “We were not interested in selling out, but we sold a portion,” he states.
Not only did that transaction provide Goodrich a sudden infusion of drilling capital, but he says it also offered a window into how a pioneering shale player was approaching the play.
“Goodrich had drilled horizontal wells before, but this was a different beast with high pressures and high temperatures,” Turnham acknowledges. “We wanted to learn Chesapeake’s best techniques and then apply them on the remainder of our acreage.”
According to Goodrich, that position amounts to more than 85,000 net Haynesville Shale acres, 60,000 of which are held by production. The company’s 2010 plans call for investing $165 million to drill 41 gross and 20 net wells with 3.5 operated rigs and a similar number of nonoperated rigs.
East Texas Specifics
Turnham indicates Goodrich has learned a lot from the 25 Haynesville wells it has drilled, a process which he says typically requires a little more than 40 days. Lateral lengths, he says, differ depending on whether the well is east or west of the Texas/Louisiana border.
“East Texas does not have the same length limitations as North Louisiana,” Turnham observes. “Louisiana is composed of square-mile town sections, which limits the laterals to 4,600 feet. In Texas, where you can form irregular-shaped units extending beyond a square mile, we are drilling 5,000-5,500 foot laterals and are likely to go longer.”
Goodrich is experimenting to ascertain its best bit and mud programs, and also to learn where to site a well’s horizontal portion so it can achieve maximum drilling speed without constant concerns about drifting out of zone, he lists. However, the company’s greatest Haynesville strides seem to be with its completions.
Initially, Turnham explains, Goodrich would frac a 4,600-foot lateral in 12 stages averaging 375 feet each. The initial scheme called for placing perforations in four cluster sets. “The thought was to limit the entry points and get some length into the formation to pull gas from greater distances,” he elaborates. “It has worked much better to double the number of perforation clusters, so instead of pumping fluid and proppant through 20 perforations over a 375-foot interval, there would be 40 holes.”
The concept, he says, is the well bore equivalent of seeking treasure close to home. “We want to better stimulate rock nearby,” Turnham says. “Our frac wings are not nearly as long, but we are pulverizing the rock near the well bore and have seen great results, not only on 24-hour and 30-day production rates, but also with flatter decline curves.”
Goodrich also has learned to vary the stimulation according to a well’s location, Turnham notes. “We have increased the stages in East Texas to 20, taking the intervals down from 375 to 260 feet,” he reports. “We have, perhaps, cracked the code on how to achieve better wells in East Texas, where the quality of the rock is not quite as good. It needs better stimulation to flow, and we are putting our normal fracs on smaller intervals.”
Turnham says Goodrich also has seen results from not pulling its wells too hard. “Smaller choke sizes manage the difference between bottom-hole and surface pressure,” he points out. “We are trying to minimize that drawdown, which is keeping a back pressure on the well, and that seems to flatten the curves.”