Eagle Ford Overview

The sun shines through the derrick of Helmerich & Payne’s Rig #254 as it drills for Eagle Ford reservoirs.

There's a burgeoning play afoot in the brush country of South Texas. In and among the thorny shrubs, prickly pears and scattered live oaks rise tall derricks. Some 45 rigs are drilling for Eagle Ford shale in this storied part of Texas, the land of Texas Rangers, hardened desperadoes and Mexican revolutionaries.

The Eagle Ford shale trend ranges some 330 miles from Grimes County down to the Rio Grande in Webb County. The Cretaceous play has blossomed like the desert after spring rain: it is delivering remarkable wells, especially in La Salle, McMullen and Live Oak counties. (For more on the geology and genesis of the play, see "Fly Like An Eagle Ford," July 2009, Oil and Gas Investor.)

Sharpshooting the Shale

Dallas-based Pioneer Natural Resources Co. has been the talk of the Eagle Ford of late, with completion of its Robert Crawley Gas Unit #1 in Live Oak County. The well, east of Petrohawk Energy Corp.'s Hawkville Field, was recently completed for 17 million cubic feet per day, the highest rate yet announced in the shale.

Pioneer's 310,000 acres prospective for the shale are spread across the margin of the Edwards shelf. The Crawley is the company's third horizontal Eagle Ford well; its first was the #1 Friedrichs Gas Unit, in DeWitt County. "We did not get a proper completion in the Friedrichs," says Tim Dove, president and chief operating officer. "The horizontal section was not properly situated within the pay zone, so only a couple of frac stages were successful." Nonetheless, the well initialed at 2.7 million cubic feet of gas and 160 barrels of condensate per day from a partial completion.

"We then focused on getting a successful well down, both to prove up the area and to show Pioneer could get these wells down technically, and on budget and on time," says Dove.

Tim Dove, president and chief operating officer, Pioneer Natural Resources, says Eagle Ford development on the company’s huge acreage position will potentially demand thousands of wells and billions of dollars.

The company's second test was much more satisfying. Pioneer moved southwest to its Live Oak County acreage holdings and drilled the Sinor #5. That test flowed 8.3 million cubic feet of gas and 500 barrels of condensate per day, firmly in the liquids-rich slice of the shale play. Its 2,600-foot lateral was fractured in nine stages.

"We were able to see a substantial amount of condensate in the well, and liquids-rich gas," says Dove. Given today's oil and gas prices, Pioneer was quite encouraged by the economic implications. Indeed, the liquid component of the Sinor, both in condensate and natural gas liquids, boosts its revenue to the equivalent of a 19.3-million-per-day dry gas well.

Next, at a location three miles south and downdip of the Sinor #5, the Crawley #1 was tested at 17 million a day on a 24/64-inch choke with 7,300 psi wellhead flowing pressure. The Eagle Ford was encountered 1,000 feet deeper than in the Sinor, and was firmly in the dry gas window. The Crawley was completed in a 5,400-foot lateral with a 16-stage fracture stimulation.

"We believe the Crawley to be the highest-rate gas well yet drilled in the Eagle Ford shale," he says. "It was very encouraging and highly economic." The company now has a two-rig horizontal campaign under way to assess resource potential across its acreage, which can be split into three areas, depending on the liquids content of the shale. The Eagle Ford play grades from oil to gas/condensate to dry gas in the dip direction—from the northwest to the southeast—across its extensive trend.

"About 70% to 75% of our acreage is in the gas/condensate window," says Chris Cheatwood, executive vice president, geoscience. The current drilling drive features a couple of wells near the Sinor and Crawley, and also locations much farther northeast. "We have two wells currently drilling in the gas/condensate window up on the Edwards margin," he says. The company is testing different portions of its extensive leasehold to determine the variability of the shale. "We feel like we are a technology leader in the play," says Dove. "We have a huge 3-D seismic database, and we've drilled through this reservoir for years." Throughout 2006 and 2007, Pioneer shot 2,000 square miles of 3-D seismic for Edwards development, which lies immediately below the Eagle Ford. Now it's taking advantage of that impressive dataset for its Eagle Ford efforts.

The Eagle Ford play grades from oil to gas/condensate to dry in the dip direction - from northwest to the southeast - across its extensive trend.

"We have a very detailed picture of both the Eagle Ford and Edwards," says Cheatwood. That's necessary for precision targeting of its laterals. The company places heavy emphasis on geosteering and keeping horizontals within the correct zones. "e think this approach makes a tremendous difference in results." Pioneer also employs seismic attributes, such as a coherency processing, to improve its imaging of faulting and fracturing in the Eagle Ford. It prefers to drill in areas with minor fracturing that will enhance productivity, but without major faulting that can provide conduits for water. "Until we learn differently, we want to stay away from large faults," says Cheatwood. Additionally, the company uses seismic to figure the direction of maximum stress, and then orients its laterals perpendicular to that direction.

On the drilling front, Pioneer is stretching out its laterals, to determine the relationship between recoveries and lateral length and frac stages. "We're in an experimentation mode now," says Cheatwood. At present, 5,000-foot laterals seem optimum, achieving a balance between sufficient length and mechanical risk. Like other operators in this shale play, Pioneer cements liners in its laterals.

During completion, microseismic monitoring is a prime tool. "Microseismic has been an eye-opener for us," he says. One benefit the company enjoys is an abundance of potential monitor wells, due to its extensive Edwards drilling. The microseismic data allow Pioneer to size its fracs appropriately. In a field development mode, Pioneer expects per-well costs to fall to between $6- and $7 million. "We're still in the experimentation mode, doing a lot of research, but we expect to pull down well costs as we move forward," notes Dove.

Meanwhile, Pioneer also has a substantial number of Edwards locations in inventory. "We're evaluating what's going to happen with gas prices this year and beyond," he says. "These are dry gas wells, and if we feel confident gas prices will be $5 to $6 per thousand long-term, we'll drill the Edwards as well as the Eagle Ford."

Pioneer is contemplating extensive Eagle Ford development across a substantial swath of acreage, and as part of that effort it is currently seeking a joint-venture partner. "Potentially the Eagle Ford will demand thousands of wells and billions of dollars. It sets itself up naturally for a JV partner for Pioneer," says Dove. The company would like to accelerate drilling to preserve its acreage, as leases in the area typically carry three-year primary terms with two-year options. "Accordingly, lease preservation is of the utmost importance."

Accelerated drilling can also substantially increase the net present value of the play. Production, cash flow and reserves would all advance. "From our standpoint, we wish to continue our model of running a company that generates free cash flow. We do not want to overspend our cash flow or in crease our debt."

The Eagle Ford has rapidly become one of Pioneer's premier projects. The company has its data room open at present and will take bids in the second quarter. Not surprisingly, industry interest in its impressive position has been strong. "We hope to tee up a massive drilling acceleration by midyear," says Dove.

Corralling a Reservoir

Rig hands make a connection on a Pioneer Natural Resources well targeting Eagle Ford shale. Drilling costs vary in the play, depending on vertical depths to the shale, the need for intermediate casing strings and length of laterals.

It's been barely 18 months since Houston-based Petrohawk Energy announced the first commercial success in the Eagle Ford. La Salle County, once notorious for fence cutting, cattle rustling and general lawlessness, is the center of today's Eagle Ford development, most particularly in Petrohawk's Hawkville Field area.

From zero volumes in 2008, Petrohawk now operates gross production of 63 million cubic feet of gas and 1,000 barrels of condensate per day. The company holds approximately 217,000 net acres in its Hawkville area alone and has drilled some 25 Eagle Ford tests to date.

"The shale plays are developing much more quickly now than in the past," says Dick Stoneburner, Petrohawk's president and chief operating officer. "We are certainly becoming more adept at figuring out how to make them work."

A real positive for the play is the lack of surprises, he says. All of Petrohawk's drilling has resulted in very consistent production and geological interpretation. "In addition to the consistency that we've seen in Hawkville Field, we now have Pioneer's success at its Crawley and Sinor wells to the northeast. That's effectively de-risked most of our acreage in the immediate area."

Petrohawk now knows, thanks to the Crawley well, that dry gas occurs at depths of 14,000 feet just off the northeast flank of its Hawkville acreage. "We don't know yet at what depth the shale will go from gas/condensate to dry gas: is it at 12,500 feet, or 13,500 feet?" Stoneburner suspects that significant slices of Hawkville Field will be in the dry-gas window, both on its northeast and southwest sides.

"At Hawkville Field, we are developing both the high-condensate-yield and dry-gas areas, but we are building our position in areas up the trend to the northeast that feature high condensate ratios."

On the drilling front, the company is focusing on longer laterals. It has taken wells out to 5,500 feet. Like others, it sees a reationship between lateral length and estimated ultimate recoveries. "We see that very definitively. We intend to go to 6,000 feet and longer this year." Average recoveries per well range between 5- and 6 billion cubic feet equivalent. Petrohawk's area carries a fair amount of faulting, but the company has used its existing 2-D seismic dataset to avoid entanglements. It is also participating in a group 3-D shoot that will total 450 square miles by year-end.

Well costs could rise with increasing depths and longer laterals, from present-day prices of $5 million per well to perhaps $6 million, says Stoneburner. "In addition, we're also seeing service-sector prices come back from the depths." This year, Petrohawk plans to spend $350 million in the Eagle Ford and drill 60 operated and 22 nonoperated wells. That includes work in its new joint venture with Swift Energy Co., in which it is drilling its first well.

Additionally, the company holds 89,000 net acres in Zavala County. Here, the Eagle Ford is shallower, lower pressured, and in the oil-prone wedge of the trend; it's about 120 feet thick and occurs at depths of 5,500 feet. The first well at Red Hawk is down and is waiting on completion, says Stoneburner. From scattered well control, the company expects products to be oil and a bit of casinghead gas. "We are looking for the revenue bump we get from oil over gas production these days in Zavala County," he says.

To date, although there's much talk about oil in the Eagle Ford, companies are mainly producing condensate, albeit at yields rumored to be in the 300- to 400-barrels-per-million range. That's not nearly as difficult as producing 35-degree-gravity oil through the tight shale, says Stoneburner. "Our biggest challenge at Red Hawk is inducing sufficient permeability with our fracture stimulations to produce oil in commercial quantities."

From a regional trend standpoint, Petrohawk eagerly awaits some comments from operators working in the updip area, northeast and northwest of Hawkville, where the Eagle Ford is thinner and oilier, he says. "In general, there are pockets of success that could expand into a continuous trend."

This year will be a breakout year for the play. "We're going to be hearing more results, and these will prove that the Eagle Ford belongs in the same breath as the Haynesville, Barnett, Woodford and Fayetteville."

Saddling Up

Swift Energy Co. has been working South Texas for more than two decades, says Bob Banks, executive vice president and chief operating officer. Most particularly, the company has been operating 66,000 gross acres in AWP Field in McMullen County, on trend with Hawkville Field. In addition, it has tens of thousands of acres spread across the Olmos trend, much with deep rights.

Pioneer places heavy emphasis on research and data collection in its current Eagle Ford shale drilling program. This test in DeWitt County, Texas, is about four miles northwest of Yorktown. It reached a total measured depth of 18,246 feet.

Swift wanted a partner to help spur the evaluation of its wealth of acreage. "We have brought Petrohawk in on 26,000 acres of our McMullen County leasehold, in the central part of our field," says Banks. "We retain a lot of 100% acreage to the north and south." The JV calls for Petrohawk to drill and complete the new Eagle Ford wells, and Swift to produce them. The latter firm has extensive infrastructure in and around AWP Field, making the JV a good fit. Additionally, Swift is drilling 100% Eagle Ford wells on acreage outside the JV; its 76,000 net undeveloped acres prospective for the shale run from Dimmit and Webb counties, once part of the turbulent and untamed Nueces Strip, to north of AWP Field. At present, the company is running one rig, in addition to the JV rig operated by Petrohawk.

"We think for the remainder of 2010, we will run at least three rigs gross," says Banks. "This is an evaluation year for us." The company's acreage spans the liquid, gas/condensate and dry-gas portions of the play, but the bulk of its holdings fall in the gas/condensate window. It plans to evaluate its acreage as rapidly as possible to understand what it has, so this year's program calls for extensive coring and log analyses.

Conceptually, Swift is planning for 320-acre spacing on its Eagle Ford wells, but expects that to drop. Thus far, no drilling issues or problems have been encountered. In its areas, the operator has been able to eliminate an intermediate casing string, bringing its well costs down to some $5- to 5.5-million apiece. Open-hole rotary steering assemblies have also contributed to efficiency.

"We see a correlation of higher IPs and EURs with longer laterals and more frac stages, and so far, we are drilling our laterals in the range of 3,500 to 4,500 feet." As the data stream in, the size and quality of the Eagle Ford shale has been more fully revealed. "So far, we see that the good-quality Eagle Ford is fairly extensive."

The play is developing quickly, and although it's in a mature area that has been produced for years, new leases are still available. South Texas owners are savvy and selective, and Swift's long presence in these counties counts heavily in its favor. "We pride ourselves on our history in this area, and our track record. We try to be good stewards of the land," says Banks.

"It used to be that landowners were happy to lease their land in the hopes that someone might drill some wells and provide them with royalty payments. Now many landowners understand that they may well be sitting on tremendous fortunes and are very cautious about who they offer leases to."

Marketing is not yet an issue, but may soon rear up with all the activity. "South Texas has a lot of infrastructure, processing capacity and access to markets," he says. The AWP area is blessed with infrastructure, but down in Dimmit and Webb counties the systems are fairly sparse.

"In our southwest areas, we have to test our position before we can justify appropriate infrastructure agreements," he says. "But the midstream companies are really tackling the Eagle Ford, and we've been pleased with their interest."

Meanwhile, the company continues to drill the Olmos at AWP. "Some of what we are doing in the Olmos is every bit as good as the Eagle Ford," notes Banks. Swift has been running a rig in that play, and will likely have one of its 100% rigs drill both Olmos and Eagle Ford wells, and devote the other 100% rig strictly to Eagle Ford work.

Good Pastures

Two copious Eagle Ford wells have been recently reported by privately held Common Resources LLC in southeast La Salle County in the gas/condensate window: the STS #29H flowed at rates as high as 14.6 million cubic feet equivalent per day, with flowing wellhead pressure of 5,000 psi, and the NMC 150 #1H flowed 17 million a day equivalent on four-point test, with flowing casing pressure of 5,426 psi. Common's first test was completed with 15 frac stages, and the second took 17.

"Any way you cut in, they are good wells," says Roger Jarvis, founder and chief executive. "We think they are among the best wells in the play." The Houston-based firm holds 46,000 gross acres in the Eagle Ford on the south side of Hawkville Field. "At this point, we are ring-fenced: we've got producing wells all around us," he says.

The firm has completed four wells to date, and is completing a fifth that offers exceptional promise. "The STS A-36 #1-H encountered the thickest Eagle Ford section yet seen in the play," he says. Logs show between 370 and 380 feet of Eagle Ford above 18% density porosity.

Common deliberately targeted the thickest part of the Eagle Ford in its acreage acquisition, and in the Eagle Ford the thick shale is also rich and highly porous. Jarvis says Hawkville could be somewhat unique in the trend, since it lies between the Edwards and Sligo shelf edges. "We think we're in an intra-shelf basin where the organic-rich section of the Eagle Ford attained exceptional thickness. The shale is at least 200 feet thick across our entire position." That equates to a lot of gas: overall, Common estimates it has 1.4 trillion cubic feet of net recoverable resource on its acreage.

Hawkville currently has 29 completions and another 59 wells either staked or drilling. "Results have been very consistent," says Jarvis. "Our average completion to date on state test is almost 11 million a day." The huge flow rates are buttressed further by consistent drilling conditions. One of Common's wells reached a measured depth of more than 18,000 feet in about 25 days.

Common's acreage falls about half in the dry-gas window and half in the high-yield condensate area. It completed its first well, STS 45 #1-H, for 4.8 million cubic feet of gas and 474 barrels of condensate per day. It came on at a yield of 100 barrels per million in July 2009, and continues to produce at that ratio.

"Across our acreage holding, we estimate we can recover 5 billion cubic feet equivalent per well. And our declines have been shallower than we anticipated, so these estimates could be conservative." Common assumes 25% recovery of in-place gas, and figures drainage areas are about 80 to 85 acres per well. To aid its understanding of the play, Common has run a number of microseismic surveys. "Our emphasis is on creating a complex network of fractures close to the wellbore," he says. The goal is to really disrupt the rock around the wellbore, a challenge in such a thick reservoir. "Tortuousity is what it's all about, the complexity of the frac." To that end, Common is tightening the distance between stages: on its most recent completion, it brought spacing down to 315 feet.

"The Eagle Ford is all about the completion," says Jarvis. "We think there's ground to be gained in frac efficiency, and we're focusing on that. In the long run, we think recoveries could exceed 30% in this reservoir."

Common plans to keep a rig busy in the Eagle Ford throughout most of 2010. Longer-term it plans to work up to three rigs. "We can live in this play at the current gas price, no problem," he says. "The Eagle Ford is a highly commercial, exciting play. There is a lot of gas in place, and we would anticipate a lot of activity in many more years to come."

Southwestward Expansion

Another private firm involved in the Eagle Ford is Escondido Resources II LLC. Midland-based Escondido has leased about 60,000 gross acres in the Eagle Ford trend, mainly in Webb and La Salle counties.

"We have participated as a nonoperating, working-interest owner in seven Eagle Ford wells so far in La Salle County, and recently drilled our first operated Eagle Ford well in Webb County in the dry gas portion of the play," says president Bill Deupree. The latter well, in the far southwestern reaches of the trend, encountered more than 300 feet of Eagle Ford. It is scheduled for 21 frac stages in its 5,600-foot lateral, the most stages yet attempted in an Eagle Ford horizontal.

Bill Deupree, president of Escondido Resources II LLC, says the company worked the Olmos and Escondido sand plays in South Texas before the Eagle Ford burst on the scene. Now Escondido has added the shale to its repertoire.

The company is the successor to Escondido Resources LP, an entity formed in 2004 to focus on the Olmos and Escondido reservoirs in Webb, Dimmit and La Salle counties. It was quite active: between 2005 and 2007, Escondido drilled more than 200 wells in South Texas. In October 2007, the first Escondido sold its assets and reformed as Escondido Resources II.

"Our focus was again on Olmos and Escondido trends," says Deupree. "But there was some shale activity going on in the area, so we started to look at the deeper horizons."

Escondido is evaluating its Eagle Ford potential while continuing its ongoing development of the Escondido and Olmos. Additionally, it is taking horizontal drilling technology from the Eagle Ford and applying it to the traditional objectives. The company drilled a horizontal Escondido well off the same pad as its initial Eagle Ford test. Both will be fractured together, with stages alternating between the adjacent laterals.

The company will employ much the same approach going forward. "In Webb County, we have objectives in the Wilcox, Escondido, Olmos and Eagle Ford sections. We have a lot to work with, and the economics on the shallow plays are good as well," he says.

In the Eagle Ford specifically, its goal is to get its first operated well on production as quickly as possible, and then craft its program from there. The outfit will keep a rig active throughout the year, and possibly add another in the second half. "We're still leasing and building our position," says Deupree. "Our Webb County area is just now seeing Eagle Ford development, and so far it appears very promising."

Shale Roundup

"There were 11 rigs working the Eagle Ford last August; that number has nearly quadrupled to more than 40," says Manuj Nikhanj, analyst with Calgary-based Ross Smith Energy Group. "The Eagle Ford is definitely attracting a lot of attention."

Manuj Nikhanj, Ross Smith Energy Group analyst, says the gas/condensate portion of the Eagle Ford play has a break-even price of $3 per thousand cubic feet, hence its popularity in today’s market.

Reasonable drilling costs and high liquids yields combine to make investments in the Eagle Ford very attractive in today's price environment, he says. The Eagle Ford is easier to drill than the Haynesville shale in East Texas and North Louisiana, a very high-pressured and hot reservoir. "A horizontal Eagle Ford well can be drilled and completed for $6 million, which is much less expensive than a similar-depth well in the Haynesville that can run upward of $10 million."

Because the play is so new, however, questions revolve around the rates and declines of Eagle Ford wells. "We're keeping a close eye on the decline profiles," says Nikhanj. The Barnett shale of North Texas is used as a standard to measure declines in modern, horizontal shale wells, while the Haynesville shale sets the floor with its steep declines. "At this point, average Eagle Ford decline profiles appear to bounce between those two levels," he says. "We're monitoring this closely."

For dry-gas wells, Ross Smith calculates a break-even price of $3.93 per thousand cubic feet on half-cycle economics. "In the gas/condensate area, if we assume a yield of 50 barrels per million cubic feet, and 90% of dry-gas deliverability, we estimate a break-even of $3 per thousand for those wells," he says. "Liquids from processing, depending on yields and midstream arrangements, can add 30% to estimated ultimate recoveries. It's one of the reasons the play is so popular."

Then too, there's much interest—as well as secrecy—about activities in the updip oily window.

Half-Cycle Break Even Sensitivities by Eagle Ford Play Type

"We hear continuing, unconfirmed reports of 1,000-barrel-a-day wells in the oil window," he says. Data are scarce, but 10 rigs are running in the oily area. EOG Resources has spearheaded work in this sector of the Eagle Ford, with five rigs in the play, including three in northern Karnes County. Operators Murphy Oil, Anadarko Petroleum, Dan A. Hughes and ConocoPhillips all are poking holes as well.

Only one well has public data available: EOG's Milton #1H made about 100 barrels a day from April through October 2009. But, in November 2009, it averaged 569 barrels of oil and 494,000 cubic feet of gas per day.

"EOG's level of activity in the Eagle Ford definitely suggests it is very happy with what it sees," says Nikhanj.

So are many other operators.

Certainly, in the wild and dangerous country once subdued by the legendary Captain McNelly and his Texas Rangers, good fortune may await the persistent. This land of chaparral, vast cattle ranches and Old West lore is rising again as home to one of the nation's principal shale plays.