Deep, Tight Gas

Onshore U.S. basins are loaded with natural gas resources, and some of these resources lie at tremendous depths. A host of basins contain thousands of feet of sedimentary rocks that have barely been scratched by explorers.

These deep rocks are home to untapped trillions of cubic feet of natural gas. Remarkable attention has been focused in recent years on unconventional shale and tight-gas plays, and now unconventional reservoirs in the deep domain are gaining traction.

According to the most recent report of the Potential Gas Committee, approximately 22% of potential onshore gas resources lie at drilling depths below 15,000 feet.

The new stripe of deep resource play yields wells that can produce at rates north of 20 million cubic feet per day. Select wells in the Deep Bossier play in East Texas, for instance, have produced for months at rates of more than 50 million cubic feet per day.

But the ultra-deep wells that tap these prolific reservoirs are fraught with challenges. It takes elite engineers to coax boreholes to their objectives in harsh and hostile basin deeps.

Problems are legion: The searing subsurface temperatures and crushing pressures can play havoc with electronic and mechanical components in downhole equipment. The stunning lengths of pipe that have to be tripped in and out of a hole for each operation consume hours and days of precious time, and the goings on at bits or perfs can be obtuse.

Furthermore, rocks at great depths are sometimes stuffed with corrosive fluids and gases. And they are beyond hard, so bits grind mightily but make scant headway.

It adds up to millions of dollars, big rigs and bigger AFEs (authorizations for expenditure). Today’s exclusive club of ultra-deep operators concentrates on three deep resource plays, each of which holds astonishing potential. From the East Texas Basin to Oklahoma’s Mountain Front to West Texas’ Delaware Basin, explorers are going after reserves locked in tight, overpressured sands and carbonates buried at terrific depths.

And, these are wells that must be stimulated. Deep, tight gas is the new “new thing.”

Deep Bossier

The play that has grabbed center stage is the Deep Bossier, a blazing trend that is rapidly developing basinward of the Jurassic shelf edge in East Texas.

The recent announcement that Calgary-based EnCana Corp. was purchasing private firm Leor Energy’s East Texas assets for $2.55 billion snapped attention to the quality and extent of the Deep Bossier.

Leor’s assets lie in and around Robertson County’s Amoruso Field, one of the top onshore discoveries in recent memory. The Houston-based company owned 35,700 net acres in its Amoruso and South Hilltop blocks, and EnCana estimates the properties contain 1.3- to 1.8 trillion cubic feet (Tcf) of recoverable reserves. EnCana already held 180,000 net Deep Bossier acres, and the addition of Leor’s properties brought its net ultimate recoveries from Deep Bossier reservoirs to between 2.4 and 3.3 Tcf. Finding, development and acquisition costs are estimated at $2.50 per thousand cubic feet.

Amoruso Field’s production has grown from nothing in November 2005 to 215 million cubic feet per day. The wells are exceptionally fine, with sterling initial rates and quick payouts. In a mere seven months, the two stoutest wells in the field, the #1 Bonnie Ann and #1 McLean, produced 10 billion cubic feet (Bcf) and 9.4 Bcf, respectively. EnCana’s best well, the #2 Laxson, was brought onstream in September 2007 and has been producing at a gross rate of 65 million cubic feet per day.

This is a deep, overpressured monster. The company has completed 30 producing wells in the field, and holds another 370 locations at spacing between 80 and 160 acres. This year, EnCana plans to operate between eight and 12 rigs and drill 35 to 45 wells. Two to four of those wells will be exploratory tests in the greater Deep Bossier trend.

A typical 17,000-foot Amoruso well is forecast to recover between 8- and 13 Bcf of gas. Vertical wells take 90 to 100 days to drill and cost $10 million each. Ones that encounter very good reservoirs can require mud weights of 18 pounds per gallon.

EnCana expects Amoruso’s year-end 2008 production to land between 315- and 355 million cubic feet per day.

“We believe Amoruso Field is the best emerging unconventional gas play in North America,” said Randy Eresman, president and chief executive, during a conference call. Indeed, Amoruso Field has the potential to become the top resource play in EnCana’s muscular portfolio.

EnCana purchased two land blocks in the productive area, Amoruso and South Hilltop. Its present production is concentrated on Amoruso. “The South Hilltop block lies downdip, and we don’t know to what extent it will contribute to overall production, but we consider it highly prospective,” says Jeff Wojahn, Denver-based executive vice president and president of EnCana’s U.S. division.

Going forward, EnCana has two primary goals in East Texas: to lower well costs and improve reservoir characterization. The company uses fit-for-purpose drilling rigs that include top drives, high-capacity mud pumps and features that allow easy moves between locations. One particularly effective approach has been underbalanced drilling through the 3,000 to 4,000 feet of Travis Peak section in each well. The operator found that it could double its rates of penetration by drilling the interval with water.

Another focus is better field mapping, to improve well-specific casing designs and eliminate unnecessary liners. “We’re also working to improve our diagnostics for completions, to decide which zones should be stimulated and how big the jobs should be.”

Aiding these cost-shaving efforts is a moderation in the steep increases in rig rates and major completion services that operators have suffered for the past several years. With stronger efficiencies, and some help from market conditions, EnCana expects to drop its average well cost to $9 million in 2008.

The company is also at work integrating data from a large 3-D seismic spec shoot with its well control. “We expect the 3-D survey will give us a much better understanding of the faulting and structural complexity of the field,” says Wojahn. It should also help identify the existence and extent of reservoir compartments.

“The breakthroughs that led to Amoruso and (nearby) Savell Field were the recognition of a strong geologic opportunity and the ability to lower costs to the point the wells were commercial,” he says. “The Deep Bossier trend is very exciting, but it’s very early days. We do not fully understand the geology yet, and we still have a lot of questions.”

Discovery of Amoruso

Leor Energy became famous overnight for the $2.55-billion sale of properties to EnCana, but the private Houston firm spent several years building its foundation in the Deep Bossier. “The asset that EnCana has acquired is by far the best asset in North America right now,” says Guma Aguiar, chief executive. “This field is spectacular.”

Leor was formed in late 2004 with a goal of making direct investments in ground-floor exploration projects. Aguiar, who had managed energy assets for his family for several years, met geologist John Amoruso by chance.

Amoruso, past president of the American Association of Petroleum Geologists, had put together a Deep Bossier prospect in Robertson County with his company Legends Exploration, a partnership with Larry Bartell and Denny Bartell. His idea was that pulses of sands had flowed off the Jurassic shelf edge, and that characteristics of the shelf edge affected where the sands had accumulated.

The explorer had worked East Texas since 1963, and had a wealth of ideas. Some years prior, as drilling in the Bossier play on the shelf blossomed, Amoruso looked for an extension in an area that might have open acreage. “Older wells in the Dew and Mimms Creek developments to the north showed a build-up of sands, and these sands built to the east,” he says. “I looked for the most likely place a concentration of these sands could be found over the Jurassic shelf edge.”

The prospect was conceptual—only a scattering of wells had been drilled in the Deep Bossier, and none were close to the targeted area. Legends didn’t have seismic over the idea, and didn’t even have information on some of the wells. It was rank wildcatting.

Leor took the deal and began to buy leases. Between late 2003 and 2005, it picked up nearly 40,000 acres that were either open or became open. The company leased everything it could get east of Burlington Resources’ Savell Block (now owned by ConocoPhillips) to the Navasota River at the Robertson and Leon counties’ border.

“We feel very good about our work with Leor, and particularly Guma,” says Amoruso. “He’s a first-class person and you can trust his word. He liked us and we liked him; we supplied the technical capabilities and Guma brought the money to make it possible.”

Leor drilled its first well in mid-2004, and additional successful tests followed that one. Although the wells were promising, they didn’t receive widespread notice.

EnCana first invested with Leor in mid-2005. The Canadian firm farmed in for a 30% interest in Leor’s assets and assumed operations. Later than year, Leor obtained senior-note financing, and in early 2005 Goldman Sachs made a $45-million private placement in the company.

Drilling continued, and so did success. But excitement really kicked up in June 2006 when the partners drilled the #1 Travis Morgan, a well that was completed for 23.9 million cubic feet a day. EnCana bought another 20% in Amoruso Field.

The two firms had completed about a dozen wells by that time. “We traded acreage with EnCana to get its working-interest position to 50/50,” says Aguiar. “We received $242 million in cash and 8,000 net acres.”

More financing was arranged, including a $150-million revolving credit facility with JP Morgan Chase Bank, and a $150-million private placement with Merrill Lynch.

“We continued to pick up acreage and we continued to drill really successful wells, and the value of our assets increased.”

But Leor had a decision to make.

Amoruso had turned out to be much larger than it had anticipated. None of Leor’s modeling or projections had forecast the magnitude of the Amoruso wells. Operations were ongoing and complex, and the nuts and bolts of pipelines, plants and facilities were consuming. More employees, more money and a transformation of the company loomed.

It was a good time to exit. Leor closed its third deal with EnCana in November 2007, and is now completely out of East Texas.

“We’re going to decompress a little bit. It’s been a very intense five years. I don’t know where we will go next, but we like grassroots exploration,” says Aguiar.

Southwest companion

Before Amoruso there was Savell. This field sits southwest of Amoruso, also in Robertson County. The two accumulations are geologically similar and will likely coalesce into a megafield that could cover hundreds of square miles.

Carlos Roa, Leor’s vice president of exploration, was with Burlington Resources and was responsible for Savell. “We were looking for unconventional resource plays, and we wanted to engineer our way into success.”

East Texas was an immediate focus of the Burlington team. In mid-2001, it looked at a Deep Bossier prospect from T-Bar-X Ltd. Co., a small prospect shop in Tyler, Texas, headed by ex-Sohio executive Tom Barrow.

T-Bar-X had assembled 25,000 acres in Robertson County and had shot a small 3-D seismic survey on its block that showed a large fault and expanded Bossier section. After evaluating the prospect for about eight months, Burlington bought it.

“We had the concept that there was a downdip play, and a smattering of deep well control and seismic indicated Bossier sands could be present and porous,” says Roa. Burlington agreed to carry T-Bar-X for interests in six wells.

Burlington’s first well was the #1 Cole. It just touched the Bossier and it encountered far higher pressures than the company had anticipated. The well was nearly lost, and although it was eventually completed, it was not commercial. The next attempt, #1 Martin, didn’t go any better.

Finally, the company drilled the #1 Smith. In March 2004, that test found two beautiful Deep Bossier zones. That well made 30 million per day flat for a year, and has already produced 23 Bcf.

Other whoppers followed: #2 Cole, which has made 26.8 Bcf to date; #3 Martin, 14 Bcf; #2 Reagan, 13.3 Bcf; #2 Sorrels, 10.6 Bcf; and #1 Read and #1 Sullivan, 9.8 Bcf each. Since first gas flowed in April 2004, Savell has produced 174 Bcf.

Robertson County’s Savell and Amoruso reservoirs are likely shelf-edge sands that were deposited in water depths between 100 to 300 feet, says Roa. “Proximity to the shelf and downdip to the main geopressure sealing fault is crucial to encountering higher-quality Deep Bossier pay zones. We mapped a lot of net sands updip so we could project potential feeder channels in the downdip direction. There are also some long-shore effects that pushed sands to the southwest.” Bossier tests drilled on the upthrown side of the geopressure sealing fault require mud weights in the 15- to 16 pounds-per-gallon range, whereas the wells downdip require 17 to 18 pounds.

Some of the best reservoirs in Savell are just 20 to 40 feet thick. Massive intervals—as much as 200 feet—have been stimulated, but those haven’t performed as nicely.

ConocoPhillips acquired Burlington in 2006 and has continued to develop Savell.

“Since the discovery of Savell in 2004, we have drilled 57 wells in the field and currently produce more than 180 net million cubic feet per day, out of 230 million gross,” says Randy Nesvold, manager of North American development, ConocoPhillips’ Gulf Coast business unit, Lower 48 region.

The major has five rigs operating in the field and plans to maintain an active drilling program. “Savell is a core asset for ConocoPhillips, and production from the field currently accounts for approximately 5% of our Lower 48 gas production.”

First major find

Hilltop Resort Field abuts Amoruso Field directly to the east, across the Navasota River in Leon County. Houston independent Gastar Exploration Ltd. has been working Deep Bossier at Hilltop since 2000. It drilled its discovery well in 2003, and now is on its 19th test on the property.

The Deep Bossier section at Hilltop is related to Amoruso and Savell, but also has marked differences. Hilltop hasn’t enjoyed the 50- and 60-million-per-day wells encountered in Amoruso, but the property has attractive economics and Gastar has steadily driven down its finding and development costs. Current production from Hilltop averages 33 million per day gross, and 17 million a day net to Gastar.

In 2006, Chesapeake Energy joined Gastar in Hilltop. The Oklahoma City concern bought a 33% interest in Hilltop and the partners formed a 13-county area of mutual interest. Additionally, Chesapeake purchased and maintains a 16.5% interest in Gastar’s common stock.

Today, Gastar has moved most of its acreage from the exploration column into the exploitation category. It currently has two rigs running in the field, one on a Deep Bossier test, #3 Wildman Trust, and one on a horizontal Knowles limestone test.

Its in-progress Bossier test offsets the #3 Donelson, Gastar’s best well to date. The #3 Donelson contains ultimate reserves of 10.9 Bcf, as estimated by Netherland Sewell & Associates Inc., and initially produced at the rate of 24 million per day. After six months online it continues to flow 13.7 million a day. It’s a single-zone completion, and has five to six additional zones with excellent potential behind pipe.

The company splits the Bossier into upper, middle and lower sections. Middle Bossier correlates to the glamour pays in Amoruso and Savell fields; Lower Bossier is below those zones and is the productive section in the Donelson and several other wells.

“We’re very excited about the Lower Bossier between 17,000 and 19,000 feet,” says Jeff Pettit, Gastar vice president and chief operating officer. “We’ve done a lot of drilling to those depths and our geologic understanding of that section is very good.”

Sands in Gastar’s Lower Bossier produce on the well-defined Hilltop structure. Gastar can correlate its reservoirs between wells, and it has identified five locations that are offsets to the #3 Donelson producer.

Middle Bossier, from 15,000 to some 17,500 feet in depth, also produces at Hilltop. As in Amoruso and Savell fields, this slice of the Bossier produces from complex stratigraphic traps, so depositional lows are the best places to prospect. “Part of our drilling plans this year is to test additional Middle Bossier concepts we’ve developed from 3-D seismic.”

Gastar plans to keep its two rigs running throughout 2008, and drill two Lower Bossier, one Middle Bossier and four Knowles wells. It may pick up a third rig to accelerate Bossier drilling, depending on drilling success and natural gas markets.

Ultra-deep costs

Lower Bossier wells offer quite different challenges than Middle Bossier ones. “Our wells are challenging to drill, and we focus on well control and well integrity,” says Gene Beck, Gastar’s vice president of drilling. “We invest $10- to $12 million in each well, and we want wells that will last.” In testament, Gastar has never had a well-control incident.

Temperatures in Gastar’s deepest pay zones reach 425? Fahrenheit, and initial pressures are 17,000 psi. These are extreme high-temperature, high-pressure wells, on a par with Lower Tuscaloosa in South Louisiana.

Wells that reach 19,000 and 19,500 feet require different casing programs than Middle Bossier tests. The extra 2,000 to 3,000 feet of hole adds cost and time, and at those depths the rule of thumb is $1 million per 1,000 feet.

“Our reservoirs are tight-gas sands, so the demands on casing designs can be as severe as anywhere in the world,” says Beck. “We are putting extreme drawdown on these wells, and our casings are designed to be totally evacuated, to run at low pressures all the way down to the perforations.”

Nonetheless, the company has pared its costs. Its first five wells in the play averaged $15.1 million each; nine subsequent wells averaged $13.6 million. Going forward, it expects to average less than $12 million per well.

On the drilling side, Gastar uses PDC bits for as much of a well as possible. That effort has cut in half the time it takes to drill the top portion of a hole. On Lower Bossier wells, once it hits the last 2,000 to 3,000 feet, it needs turbines and diamond-impregnated bits. That’s an issue Middle Bossier operators don’t face.

Eliminating noncommercial completions has been a big focus. “Something as simple as bypassing a zone that we now can recognize as uneconomic saves us $1 million in a completion attempt.” It’s a common problem across the play, mainly in more marginal wells, which are harder to recognize but every bit as expensive as the boomers to complete.

Once it selects its zones, Gastar is aggressive in its stimulations. “We’ve learned how to complete and produce these wells: how hard they can be pulled, if they need additional corrosion or inhibition treatments, or water or acid stimulations to keep deposits from building up in the casing above the perforations,” says Beck.

Today, Gastar’s Middle Bossier wells are each $10 million or less, and Lower Bossier ones are $12 million, depending on the number of zones that are stimulated.

“We’re pleased with progress we are making on costs, and on improving the economics of the play,” says Pettit. “We have a large inventory of locations that will keep us busy for the foreseeable future.”

Related but different

In Freestone County, about 40 miles north of the Savell-Amoruso-Hilltop complex lies another Deep Bossier field, Holly Branch. This accumulation, discovered in 2001, has been developed by Anadarko Petroleum, modern pioneer of the Bossier play on the shelf.

This is another high-pressure, high-temperature area. To date, the company has drilled 28 wells in Holly Branch, six of which were in its 2007 program. Operated production reached 35.7 million cubic feet per day. This year, it plans three tests in the field.

Uniquely, Anadarko targets both Bossier sands and fractured shales at Holly Branch. “We are currently completing two to three fractured shale stages in our Holly Branch wells, which are generally about 17,000 feet deep. This is one of the deepest high-pressure, high-temperature fractured-shale plays in North America,” says Allen Sanders, general manager, Bossier and Chalk operations.

Some single-stage shale completions have resulted in initial production rates of nearly 5 million cubic feet per day. “In Holly Branch alone, the shale gas in place could be in excess of 3 Tcf. Unlocking even a small percentage of the total potential could significantly enhance the economics in this field,” he says.

Anadarko is currently evaluating horizontal drilling techniques similar to those used in the Barnett shale to help monetize this potential. The high temperatures and pressures at Holly Branch push the current technological limits of horizontal drilling, so the company is proceeding carefully.

While the Bossier sands at Holly Branch have a similar depositional setting to Bossier sands found in Amoruso and Savell, there are structural differences that make each field unique.

In Holly Branch, average reservoir pressures are 14,000 psi and temperatures are 340? Fahrenheit. Net pay thickness ranges from nine to 70 feet; porosities average 10% to 15%; water saturations run 20% to 35%. “Overall the pay sands have good reservoir properties. A recent well tested a fully commingled sand and shale interval at an initial rate of more than 17 million cubic feet per day, and produced nearly 3 Bcf in a year,” says Sanders.

The average Holly Branch well has an estimated ultimate recovery of approximately 3- to 4 Bcf, and fractured shales can contribute 5% to 30% of the overall reserves.

Anadarko has a decade of experience in fracturing Bossier sand wells, and it continues to enhance that expertise. It uses hybrid fracs to complete both its Deep Bossier and shelf Bossier wells. The technique takes advantage of the benefits of both water and cross-linked frac techniques. Its overall completion design is fairly standard, with only minor changes to fluid and proppant selection to adjust for higher temperatures and pressures.

Anadarko currently owns 10,000 acres of leases in Holly Branch, and has a sizeable inventory of infill locations. “We are working on our drilling and completion practices to reduce average well costs and enhance the overall economics,” he says.

In addition, Anadarko is a leading explorer in the Deep Bossier. In Houston County, about 10 miles southeast of Freestone County, the company drilled three exploratory wells that encountered pay zones ranging in thickness from 430 to 850 feet. Industry excitement over the Deep Bossier potential in Houston County has spread, and several other operators have exploration wells in progress. Currently, Anadarko has more than 60,000 acres of leases in Houston County, and several of the ongoing tests offset its holdings.

The company also has several Deep Bossier tests—up to 20,000 feet deep—producing across the Bossier area. It is continuing to evaluate the deep play and is developing new plays on trend with the Savell-Amoruso-Hilltop complex. One or more of these ideas may be tested in 2008.

Worthy competitors

The Deep Bossier is getting crowded. Powerhouse operator Chesapeake Energy entered the play in mid-2005, after it observed Burlington’s #1 Smith discovery in Savell Field.

“We assembled all available 2-D seismic data and modeled prospect areas after Savell,” says Mark Lester, executive vice president. The company looked for buried fault systems that could have provided accommodation and early traps for sands. Its idea was that early migration of hydrocarbons into the Bossier reservoirs preserved porosities and high permeabilities.

In late 2005, Chesapeake bought into Hilltop with Gastar. Today, the company holds 380,000 net acres in the play.

Although the majority of wells in Amoruso Field have been drilled primarily from 2-D seismic data and subsurface mapping, Chesapeake is a strong proponent of 3-D seismic in the play. The company was instrumental in initiating a spec 3-D shoot that covers 370 square miles across Hilltop, Amoruso and most of Savell fields. It’s also in a 455-square-mile 3-D spec shoot that covers much of its Houston County leasehold.

“We think that interpretation of the 3-D data and attribute mapping will be crucial for well positioning and spacing, and for identifying new zones,” he says.

Currently, Chesapeake operates three drilling rigs in the Savell and Amoruso-Hilltop areas, and has two wells working on completion.

And Marathon Oil Co., ramping up activity in East Texas, has moved into the play. About three years ago, Marathon rebalanced its upstream focus to include not only significant international growth projects, but also a greater emphasis on new U.S. resource plays. To accomplish this, it infused its onshore Lower 48 exploration program with substantial capital, and the Anadarko and East Texas basins account for half of its current efforts.

“Our capital spending in the U.S. is now five times what it was in 2004,” says Steve Guidry, regional vice president, U.S. production operations. Marathon’s goal in East Texas is to duplicate the success it has enjoyed in the deep-gas Oklahoma play.

Deep Bossier is relatively new for the company. It has 165,000 net acres in East Texas, about 28,000 of which is newly acquired acreage in Deep Bossier.

“We have 30 East Texas prospects, in various stages of development, and we plan to drill four Deep Bossier tests in 2008,” says Guidry.

Future prospects

Kevin Hayden, president of Owensboro, Kentucky-based Hayden Energy Inc., founded in Houston, has worked the Bossier trend since 1990, and generated the first Deep Bossier prospects in the Hilltop and surrounding area. He worked closely with Mike Ellis of Navasota Resources and Thom Robinson and Tony Ferguson of Geostar Corp.

“Without the joint efforts and tenacity of everyone, especially early in the play, the Deep Bossier would not have achieved success,” he says.

Basinward and on strike from the prolific cluster of Amoruso, Savell and Hilltop fields, Hayden believes the Deep Bossier has tremendous additional potential corresponding to various shelf-edge locations. “That is what we are working on now. In our view, the Bossier trend will eventually cover a much larger area than at present.”

George Devries Klein, Sugar Land, Texas-based owner of Sed-Strat Geoscience Consultants Inc., has studied the Bossier across East Texas. He concluded that a drop in sea level allowed Bossier fluvial systems to extend basinward, and abundant sandy reservoirs were deposited.

“It’s an extensive trend. There are good bits of Leon and Houston counties that are waiting to be drilled, and Madison County has possibilities also. Northern Brazos County could be prospective,” he says. The shelf extends through Cherokee, Rusk and into Panola County, which means areas such as Nacogdoches County and parishes in Louisiana could join the play.

Mountain Front

Oklahoma’s Mountain Front is another tremendous deep, tight-gas play. Rigs are sprouting along a 200-mile ribbon that extends from the Cimarron Arch in the Texas Panhandle to the Nemaha Uplift in central Oklahoma. Explorers focus on a 10- to 15-mile-wide, structurally complex area that runs along the side of the Anadarko Basin.

Targets are Pennsylvanian Morrow and Springer sandstones and Lower Paleozoic Hunton and Arbuckle carbonates. Accumulations vary in size from 100 to more than 250 billion cubic feet equivalent (Bcfe).

Marathon has been a long-time and very successful player in the Mountain Front play. “During the last 10 years we’ve had nine major discoveries that contain 2 Tcf in gross reserves,” says Guidry. “Deep gas in Oklahoma has been a mainstay in our onshore U.S. exploration effort, and it’s a program that we continue to lead. We believe we have a competitive advantage there.”

Marathon targets the deep Paleozoic section, including Springer, Cunningham, Britt and Morrow reservoirs. Individual sandstones are generally between 10 and 100 feet thick, and their reservoir properties can be enhanced on structural highs and/or fault closures.

“Typically we spend between $10- and $15 million on a 20,000-foot well, and we can find between 4 and 20 Bcf per well. Average wells are 6 Bcf.”

Wells can produce at initial rates in excess of 20 million per day, but rates are variable. This is a high-stakes statistical play. “Out of eight wells, we might get two boomers and six average to less-than-average ones. The play is attractive because it delivers those high-productivity wells on a regular basis.”

Mountain Front reservoirs have inherently low permeabilities, and the reservoirs must be stimulated to produce. That brings up a challenge: Once the wells are drilled, it’s tough to tell which zones will have effective permeabilities to produce gas in commercial quantities.

“We’ve gotten much better at this during our time in the play, but it’s not easy in these deep, tight gas sands to select the best candidates for completion.” Most of Marathon’s wells encounter between three and five zones that are potentially gas-productive, and the company selects one or two for initial completion. The remaining zones are left behind pipe for later.

Marathon owns 250,000 net acres in Oklahoma, and has 65 prospects scattered along the Mountain Front trend. It currently runs six rigs.

Two factors have brought the Mountain Front play to the forefront. The first is the advent of 3-D seismic, including deep processing and the ability to image complex structures.

3-D is integral to Marathon’s strategy. The company sponsors multi-client 3-D shoots over Mountain Front areas then processes the data with proprietary techniques.

“We are quick to analyze and evaluate data from those shoots, and that drives our leasing program.” Marathon currently has rights to 3,500 square miles of 3-D seismic that cover about 60% of the Deep Anadarko Basin, and it also holds a significant amount of legacy 2-D data that it uses to high-grade its focus areas.

“Most recently we have begun to target footwall structural traps, below the hanging wall of the Mountain Front. We think there are untested opportunities all along the trend.”

One issue that bedevils explorers is that seismic cannot distinguish between reservoir and nonreservoir-quality formations. “Our ability to image sand accumulations has been good, but some sands are so tight they are difficult to produce commercially,” says Guidry.

The second factor that has enabled the Mountain Front play to take off is lowered well costs. Improvements in drilling technologies have been dramatic: Prior to the 1990s, a deep gas well drilled in the Anadarko Basin below 20,000 feet took two years; today, 90 to 120 days is the standard.

Still, like other operators, Marathon has experienced hyperinflation in well costs—up 74% since 2005. Helpfully, prices for stimulations have begun to soften, driven by large amounts of equipment moving from Canada into the U.S.

In 2008, the company will drill eight deep-gas exploratory prospects in Oklahoma. “The Anadarko is one of the largest ultra-deep gas basins in the U.S., and we think considerable untapped resources remain to be tested,” says Guidry.

Oklahoma neighbor

Chesapeake Energy is also quite active in the Mountain Front trend in its home state. The company produces 100 million cubic feet per day net there, and holds 145,000 acres of leases. It currently runs two rigs in the play.

To date, the company has found two significant Springer fields in western Oklahoma that contain 100 Bcfe and 240 Bcfe in recoverable reserves. “These discoveries also led to more deep drilling, and we found an additional 100 Bcfe in Upper Morrow zones,” says Jeff Fisher, senior vice president.

The company uses existing 2-D seismic and deep well control to delineate its prospects, and it pulls in 3-D seismic if needed. It also relies on 3-D in areas where deeper structures are not easily identified with existing 2-D data. “3-D has also been useful in finding smaller features that could not be resolved with existing subsurface control,” he says.

Chesapeake drills its Mountain Front wells with oil-based muds, due to highly reactive Springer sands. Typical reservoir temperatures in the Springer are in the range of 275?, and pressures are between 15,500 and 16,300 psi at depths between 18,000 and 18,500 feet.

“The Morrow interval, just above the Springer, gives us bigger problems as periodically we see extremely high-pressured shale-sand intervals,” says Fisher. “We have to increase mud weights to more than 17 pounds per gallon, which at times makes it tough to drill through depleted Springer below.”

In Chesapeake’s view, many untested structures still lie along the Mountain Front trend. Any one of these could have the potential of holding upwards of 250 Bcfe.

“Undoubtedly, more of these will be found as we continue to drill new wells, shoot new 3-D surveys, and evaluate our existing 3-D inventory,” Fisher says.

Deep Haley

Loving County in West Texas is also thick with big rigs. Haley Field’s overpressured Lower Permian and Pennsylvanian sandstones and carbonates are targets for a large joint venture between Chesapeake Energy and Anadarko Petroleum.

Haley has been making gas from deep Strawn and Morrow sands for 25 years, since its discovery by Amoco in 1983. The major was drilling for a deeper pre-Pennsylvanian target, but instead found gas in Strawn and Morrow reservoirs between 15,000 and 18,000 feet. Production peaked at daily rates of 45 million cubic feet in 1987, but declined to less than 10 million in the late 1990s.

Anadarko Petroleum embarked on a field rejuvenation program at Haley in 2002. It went after Haley’s unrecovered gas with tight-sand technologies.

Its success has been tremendous. Today, Haley makes 215 million cubic feet of gas per day, and has produced 320 Bcf. Individual wells can produce between 15- and 30 million per day.

Haley wells tap stratigraphically trapped Wolfcamp, Strawn, Atoka and Morrow sandstones and detrital carbonates that are stacked throughout 2,500 feet of gross interval.

Individual pay zones range between 10 and 35 feet thick, and porosities range from 4% to more than 15%. Water saturations in the better wells are in the 10% to 15% window.

Reservoir temperatures reach 230? and initial bottomhole pressures at the base of the Pennsylvanian exceed 15,000 psi.

“The play works because of the volume of stacked reservoirs available in an individual wellbore,” says Steve Randolph, general manager, Anadarko’s Delaware Basin operations. “But this attribute also produces highly variable results for individual wells.” Indeed, a 20-Bcf well can be offset by a 1-Bcf producer.

Anadarko has brought many technologies to bear on Haley’s reservoirs.

It selects locations with 3-D seismic. Anadarko calls Haley its onshore subsalt play because the reservoirs lie beneath 5,000 feet of evaporates. The salt layer makes accurate seismic images challenging, and the overpressured reservoirs add further complications.

The company applied a seismic-interpretation technology that doesn’t use velocity in the interpretation process. “We’ve found a way to use predictive decon, a fairly conventional seismic-interpretation tool, in creative ways to give us a much clearer picture of the subsurface.”

The company has also pushed to recognize pay in intervals that hadn’t been previously tested in its wells. “We borrowed techniques from other plays, and developed techniques unique to Haley, that allow us to unlock reserves that were previously unrecognized.”

The potential to expand Haley and repeat the success of the field in the Delaware Basin is significant. The Anadarko-Chesapeake JV has access to more than 650,000 gross acres and Haley development only encompasses a little more than 100,000 gross acres so far.

Joint venture

Chesapeake entered the play with a major lease effort in 2005. Soon afterwards, it completed its #31-2 J.A. Haley for 35 million cubic feet of gas per day. By the start of 2006, it had collected 125,000 acres and launched a four-rig drilling program.

In July 2007, Chesapeake and Anadarko formed a joint venture at Haley. Basically, it was a swap to even out their interests and allow an orderly development of the Haley area. The companies owned complementary land positions and believed the JV would allow for more efficient use of rigs and improve their respective understanding of the reservoirs.

Chesapeake traded $310 million and 50% interests in some nonproducing Loving County leases to Anadarko for 25% of Anadarko’s existing Deep Haley area production, 25% of its leasehold in the central and eastern portions of the Deep Haley area, and half of Anadarko’s leases in the western portion of Deep Haley.

Now, the partners have joint interests in acreage and share operations. At present, Chesapeake is operating nine rigs in the JV and Anadarko is running eight.

Chesapeake’s current net production is 105 million cubic feet per day. It estimates its risked unproved reserves are approximately 1.4 Tcf equivalent.

The JV’s 2008 drilling program will be directed 70% toward development and 30% toward exploration drilling. “A large part of our drilling effort has been focused on step-out and exploratory drilling to evaluate sweet spots as well as the limits of the play,” says Fisher.

Chesapeake figures that a typical 18,000-foot well in Haley costs $12 million completed and will recover 6 Bcfe on 320-acre spacing. “As the project continues to mature, we expect that average initial rate, per-well reserves and project economics will continue to improve.”

Costs are trending slightly downward, and drilling days have dropped from 120 per well in 2005 to 100 at present. That’s been a result of improved bit technologies and better selections for casing seats and placements of drilling liners. “We credit these savings mainly to using a consistent group of rigs and experienced personnel.”

The heftiest cost savings in the overall play, however, have come from changes in completion techniques and stimulation designs. Better pay recognition, fewer completion stages and shorter flowback time to sales have all been material.

The success at Haley has broad implications for West Texas. “The overpressured Delaware Basin under-explored,” says Lester. “We and our partner are working together to continue to expand Haley, and to develop similar prospects and new plays in overpressured, stratigraphic reservoirs elsewhere in the basin.”

Indeed, as in other ultra-deep gas plays, the companies seek that ideal place where well costs are moderate and well performances shine. Haley, Deep Bossier and the Mountain Front plays are just the beginning of a brave new world of deep, tight gas that will contribute mightily to the nation’s supply.

Bring on the big iron.