Cut by numerous deep valleys and canyons, the stratified plateaus and mesas of western Colorado are not only home to large oil-shale deposits, but one of the biggest accumulations of natural gas in North America. In this region, the 6,000-square-mile, gas-rich Piceance Basin straddles the Colorado River and Interstate 70 in Garfield and Mesa counties and extends northward into Rio Blanco County and south into Gunnison and Delta counties. Essentially a huge fluvial system that contains a large, vertically stacked sequence of sands and shales that were deposited by meandering river systems during the Cretaceous age some 70 million years ago, the Piceance is a basin-centered gas trap that may contain as much as 200- to 300-plus trillion cubic feet (Tcf) of gas resource in place. Operators that have flocked to the Piceance in recent years are hoping to recover 60% to 80% of that estimated potential, mainly from the 1,700- to 2,400-foot-thick, gas-bearing sequence in the Williams Fork section of the Mesaverde formation; the Williams Fork typically occurs at depths ranging from 4,500 to 8,500 feet in the basin. Currently, Mesaverde drilling activity in the Piceance is principally along a west-to-east fairway in the Grand Valley, Parachute, Rulison and Mamm Creek fields where the Williams Fork and lower Rollins, Cozzette and Corcoran sections of the Mesaverde lend themselves to drilling wells on 10-acre subsurface spacing. "The risk in this play isn't drilling a dry hole; the risk is all technical," says one geologist. "Very simply, we have to pay attention to drilling and completing our wells properly, and the better we get at that, the better our economics become." At present, drilling multiple directional wells from single pads and crafting more advanced completion technologies are allowing operators like EnCana and Williams to achieve average per-well recoveries of 1.2- to 1.4 billion cubic feet (Bcf). However, this is no longer a play for such large independents and industry giants like ExxonMobil and Chevron. Today, the basin is witnessing the entry of smaller operators like Bill Barrett Corp. and privately held Laramie Energy. In addition, XTO Energy this July announced it's entering the Piceance through a partnering agreement with ExxonMobil. All these industry players recognize one simple fact: the Piceance-in terms of gas-resource-potential-may well be the place to drill in the Rockies for the next 10 years. Big potential EnCana Oil & Gas (USA) Inc., the Denver-based arm of Calgary's publicly held EnCana Corp., entered Colorado's Piceance Basin in February 2001 when it acquired Ballard Petroleum. Through that purchase, it obtained some 100,000 net acres, estimated natural gas reserves of 130 Bcf and daily gas output of 21 million cubic feet from about 130 wells producing primarily at Mamm Creek. After subsequent acquisitions, including the $2.7-billion buy of Tom Brown Inc. in May 2004, the company today holds some 1 million net acres in the Piceance, of which 795,000 are undeveloped. Daily gas production, meanwhile, has ramped up to 320 million cubic feet from about 2,500 wells; proved reserves, to 1.6 trillion cubic feet equivalent. This may sound like a lot of growth, but for this operator it's just the opening round in unlocking the huge potential of the Piceance. "We and others believe there's more than 300 Tcf of gas resource in place in the Piceance, some 90 Tcf of that beneath our own holdings in the basin," says Roger Biemans, president of EnCana Oil & Gas (USA). "It's our hope to ultimately recover between 60% and 70% of that resource potential." While Mamm Creek, south of the Colorado River, represents 75% of the EnCana arm's current Piceance production, the majority of its future upside is north of the river, in the operator's North Parachute project and its Eureka play. "The continuous resource-play component of the Piceance Basin is a fluvial sand deposit of Cretaceous age, with the Williams Fork formation in the Upper Mesaverde being the predominant producing zone," he says. In Mamm Creek, this formation occurs at an average depth of 8,500 feet, and slightly deeper as one moves from the valley floor toward the North Parachute project area and the top of the Roan Plateau. There are, however, other Mesaverde sandstone horizons below the Williams Fork which are also productive, those being the Iles group of formations-the Rollins, the Cozzette and the Corcoran, which occur at average depths ranging from 8,500 to 9,000 feet. Collectively, these horizons are where 95% of the basin's gas potential is to be found. From the outset, the Piceance was a natural fit for EnCana, says Biemans. "We recognized that it would allow us to take advantage of one of our core competencies, which is to pursue resource plays where we can drill a lot of wells, almost in a manufacturing-style operation, and methodically apply drilling and completion technologies as we go along to increase recoveries and reduce costs." Last year, with a capex budget of $440 million for the basin, EnCana drilled 250 net wells; for the next couple of years, it plans to drill around 400 wells annually in the Piceance, spending $500 million this year in that effort. Its five-year drilling inventory: about 3,000 wells. To increase recoveries in a cost-efficient manner, the Rockies producer is employing in its completions, seven-stage frac stimulations per well instead of the two-stage fracs previously employed by other independents. "This has resulted in a doubling of our estimated ultimate recovery (EUR) per well to 1.2 Bcf versus the 500 million cubic feet per well realized by earlier operators," says David Grisso, Piceance field operations lead manager for EnCana. In addition, in its hydraulic-fracture stimulations, the company is using slick-water fluids-versus historical polymer gels with fairly high viscosities-to carry pumped sand or proppant into reservoirs, says Grisso. "These cleaner and less expensive fluids greatly improve the rates at which wells flow back from stimulated reservoirs. With this slick-water technology, we're able to get gas out of intervals we previously couldn't." In its well completions, EnCana is also employing microseismic mapping of subsurface intervals being targeted for fracturing to help it determine just how many frac stages will be needed for optimal reservoir recovery. The microseismic mapping is additionally helping the company identify the optimal placement of future wells to achieve the best EUR. Another efficiency on the completion side: since the operator can directionally drill 12 to 16 Piceance wells from just one pad, as is the case of its North Parachute project, and each well undergoes an average of seven fracs, that's 84 to 112 fracs that can be accomplished without moving any frac equipment. Also, whereas other producers need to truck water into a pad location for their frac jobs, EnCana uses a water-gathering line to bring water to its pads, says Grisso. "Not only does that further reduce completion costs, but it also gets a great deal of truck traffic off the road, which is a safety issue. A lot of industry accidents are traffic related." In its drilling, which represents about half the $1.2-million cost of each well in Mamm Creek, EnCana is employing a technique called managed-pressure drilling. "By being slightly underpressured and underbalanced in our directional drilling, the drillbit-which doesn't have to overcome the influence of mud pressures in cutting through a formation-is able to achieve a higher penetration rate and hence, reduce the time it takes to drill a well," explains Biemans. "Whereas an average Piceance well, using conventional drilling technology, might take 16 days to drill, we've been able in many cases to cut that time by six days." He adds that the company, which is planning a 500-mile pipeline to increase gas take-away capacity out of the Piceance, is determined to leave as small an environmental footprint in the basin as possible. "After we've completed operations at Mamm Creek, where we have an average of five wells per pad, there'll be only a single-acre production location per 100 surface acres; in the case of North Parachute, where we're drilling up to 16 wells per pad, there'll be only a single-acre location per 320 surface acres." Rigging up Primarily engaged in the finding, production, gathering, processing and transportation of natural gas, Tulsa-based publicly held The Williams Cos. got into the Piceance Basin in a big way in August 2001 with its multi-billion-dollar purchase of Barrett Resources. That acquisition gave the company daily gas production of about 150 million cubic feet from several hundred Piceance wells, booked reserves of a little more than 1 Tcf and 134,000 net acres, primarily in the Grand Valley, Parachute and Rulison fields. Since then, Williams has drilled some 700 wells in the basin, boosting daily gas output there to 370 million cubic feet. Its booked reserves in the Piceance, meanwhile, have risen to 1.8 Tcf, which represents 61% of the company's total year-end 2004 domestic reserves of 3 Tcf. What's more, the company has in the Piceance more than 250 miles of gas-gathering lines and four gas-processing plants. "This is clearly a very prolific gas basin, where it's estimated there's 100 Bcf of natural gas in place per square mile. Using that number, one can easily arrive at more than 100 Tcf of gas-resource potential for the basin's roughly 1.4 million acres that are deep enough to be productive," says Joe Jaggers, Williams' vice president, exploration and production, Denver region. He contends that Williams has a long future in the Piceance, with more than 3,000 locations to drill in the Grand Valley, Parachute and Rulison fields. In fact, with 15 rigs running at any one time, and one rig drilling 20 to 25 wells per year, it probably has a 10-year drilling inventory ahead of it-"and this doesn't include added opportunities to the north, at our Trail Ridge, Red Point and Ryan Gulch prospects." This year, the operator plans to spend around $400 million to drill 300 Piceance wells, up from about 200 wells last year. In 2006 and 2007, its drilling pace in the basin will step up to 450 wells and 500 wells, respectively. Williams is primarily targeting the Williams Fork section of the Mesaverde formation throughout the basin. The company's success rate? That's one of the beauties of drilling in the Piceance, Jaggers chuckles. "In all the time I've been here, helping to drill more than 1,000 wells, we've never encountered a dry hole. This is a play that's repeatable, that gives an operator the opportunity to figure what works best-from an efficiency and technology standpoint-then apply that knowledge on a large scale, drilling hundreds of wells per year." Indeed, attention to efficiencies has helped Williams during the past three years hold drilling and completion costs in the Piceance relatively flat at around $1.1 million per well-despite rising oil-service costs-and average finding and development (F&D) costs to around 95 cents per thousand cubic feet (Mcf). On the well-completion side, the company, as other operators, is using slick-water fluids, rather than polymer gels in its hydraulic fracs, which permit higher flow-back rates and higher recoveries from treated reservoirs. At the same time, it's using flow-through plugs above each treated interval in its multi-stage fracs, allowing the treated interval in a well to flow back the same day. "In the old days, when solid plugs were used to separate fractured intervals, it might take a week or so before a completion rig drilled all the plugs out of fractured zones and the first treated interval began flowing back," says Jaggers. In its drilling operations-directional in nature with as many as 22 wells that can be spudded from a single pad on 10-acre, bottom-hole spacing-the company is using polycrystalline diamond compact (PDC) bits that have increased downhole penetration rates by between 20% and 30%, thus lowering rig time per well. In yet another drilling-related move, the operator this March contracted with Helmerich & Payne for 10 state-of-the art, FlexRig4 drilling rigs, each for a term of three years. "These rigs have top drives, which make directional drilling much easier and faster because you're not stopping for pipe connections as often," explains Jaggers. "Also, because you're not stopping in the hole as often to make connections, there's less of a tendency to get stuck downhole." In addition, he says, the new rigs allow an operator to make more use of bottom-hole assemblies, allowing for faster penetration rates and longer well reaches. Besides this, the rigs eliminate the need for drilling-fluid pits. "All the drilling fluids and cuttings are fully contained in a closed mud system on the rig which makes for a smaller environmental footprint." Adds Jaggers, "The rigs also have automated pipe-handling systems which take people out of harm's way. And, because the rigs are all electrically, not mechanically, driven by a generator that's enclosed in a sound-proof facility, there'll be much less noise associated with our drilling operations." Piceance return Formed as a private entity in January 2002 and taken public last December, publicly held, Denver-based Bill Barrett Corp. is hardly any stranger to the Piceance Basin. Most of its management team was formerly with Barrett Resources, which pioneered the development of the basin's Grand Valley, Parachute and Rulison fields before the firm's August 2001 sale to Williams for $2.8 billion. But Bill Barrett, chairman and chief executive officer of his namesake firm and who has worked the Rockies as a geologist for nearly 50 years, has a fondnesss for replicating success in basins he knows well. Thus, in September 2004, he and his team returned to the Piceance with the $137-million purchase of the Gibson Gulch Field from Calpine Corp. The acquired parcel, some 10 miles southeast of Rifle and just east of the Mamm Creek Field, included 18,207 net acres (about 14,000 undeveloped), net daily gas output of about 7 million cubic feet from 70 producing wells and an estimated 46 billion cubic feet equivalent (Bcfe) of proved reserves. "Essentially a huge fluvial system that contains a large, stacked sequence of sands and shales that were deposited by meandering river systems during the Cretaceous period some 70 million years ago, the Piceance is a basin-centered gas trap that may contain as much as 200 Tcf of gas resource in place," says Barrett. "Operators that have flocked here in recent years are hoping to recover 60% to 80% of that potential, mainly from the 1,700- to 2,400-foot gas-bearing sequence in the Williams Fork section of the Mesaverde." In Gibson Gulch, the Piceance veteran expects a 60% recovery rate from the Upper and Lower sections of the Mesaverde. Translation: the company could potentially be looking at booking as much as 1 Tcf of gas reserves. "Even though we've earmarked $127 million-42% of our 2005 companywide capex budget-to drill 80 to 90 wells in the Piceance, we're only in the early stages of that program and really can't tell whether we'll be bringing in 1.3-Bcf wells or 0.9- to 1-Bcf wells," he says. "The only thing we know for sure is that the basin is a highly repeatable play, with long-lived gas wells and low F&D costs in the range of 75 cents to $1 per Mcf." Kurt Reinecke, vice president of exploration, southern division, for Bill Barrett Corp., says the company thus far in 2005 has drilled 20 Gibson Gulch wells, only half of which have been completed. Nonetheless, the producer has seen its daily gas output there rise to nearly 12 million cubic feet. "What has been encouraging as we've gone through the Williams Fork down to the deeper marine sections of the Mesaverde-the Rollins, Cozzette and Corcoran-is that we've encountered a lot of natural fractures; that's key to achieving higher initial production rates and higher ultimate recoveries," says Reinecke. What's also encouraging for the operator, in terms of the future economics of the play, are the results of applying new completion technologies. Besides using slick-water in its multi-stage fracs, the company has been testing in one of its well bores a new Halliburton process called CobraMax. "Effectively, it allows you to complete a well in less than 24 hours instead of the usual five days," says Reinecke. The process involves delivering frac fluids downhole via a coiled-tubing truck instead of using a conventional completion rig. Using this approach, an operator is able to perforate a zone, frac it, seal off the zone, then move sequentially uphole to the next zones for treatment, repeating the whole process again. After that, he's able to come back downhole, clean out all the sand and his well is ready for production-all this without having to repeatedly make trips in and out of the hole. "Besides the directional pad drilling we do, we're also considering horizontal drilling to access the deeper Rollins and Corcoran sections in the Mesaverde," says Reinecke. "These sections contain blanket marine sands that cover a very wide area and hence, lend themselves to the application of horizontal technology which allows the drillbit to come into contact with more of the fractures in a given section or interval. That, in turn, means less wells have to be drilled to effectively drain a given interval." In addition, the company is attempting to acquire a 25-square-mile, 3-D seismic survey in the Gibson Gulch area to help it prioritize drilling activity in the region where each well costs an average $1.4 million to drill and complete. Can BBG make it in the Piceance all over again? Judging by the company's stock performance since last December, Wall Street has already assumed that as a given. But Bill Barrett is a little more modest. He observes in an almost self-effacing way, "The wells in this basin may not be big, but you can make a few dollars here at very low costs-if you know where and how to drill." Private pursuit Laramie Energy Inc., a private Denver-based operator, isn't any stranger to the Piceance Basin, either. Jim Schroeder, the firm's president and chief operating officer, previously headed Mesa Hydrocarbons and between 1998 and 2003 grew that private Denver-based producer's Piceance gas reserves to 100 Bcf before the firm was sold to EnCana. "Recognizing the huge gas-resource potential still remaining in this basin, we formed Laramie last summer to acquire 20,000 gross acres in the basin's Colbran Valley some 10 miles south of Parachute," says Bob Boswell, Laramie chairman and chief executive officer. "The purchase included daily gas output of only 500,000 cubic feet from 19 wells and proved reserves of 18 Bcf, but we felt there was plenty of running room." Since then, Laramie, which has a $150-million private-equity commitment from EnCap Investments and Credit Suisse First Boston Private Equity plus a secured line of credit from a bank group led by JPMorgan Chase, has drilled 28 Williams Fork, Cozzette and Corcoran wells on its Colbran Valley acreage-fully fracing and hooking up 11 of those wells. The result: daily net gas production has grown to between 6.5- and 7 million cubic feet; proved reserves, to north of 100 Bcfe based on 40-acre spacing. Meanwhile, last December, Laramie looked eastward in the basin and picked up another 20,000-acre Piceance parcel, this time in the more mountainous Baldy area, six miles southeast of Rifle and just south of Gibson Gulch. While there's no existing production on the acreage, and the company has only recently spudded its first Mesaverde well there, Baldy's gas-reserve potential could be substantial, says Schroeder. With a capex budget of $100 million this year, and slightly more next year, Laramie will be drilling an average of 100 Piceance wells per year, each at a cost of $900,000 to $1.3 million, depending on depth. Says Boswell, "This is a prolific basin-centered gas play where success is a function of using efficient drilling and completion technologies that keep F&D costs below $1 per Mcf-and being attentive to environmental sensitivities." As it moves forward in the Colbran and Baldy areas, the company plans to drill eight wells or more directionally from single-pad sites, thereby leaving a small footprint on the land. "While it may cost more to drill wells directionally than vertically, perhaps $100,000 more per well, that expense is more than offset by the cost savings an operator achieves by having all his wells and production facilities on one pad-plus he doesn't have to lay as many gathering lines or construct as many access roads," explains Schroeder. The Laramie president also points out that by using a combination of PDC drill bits and the proper mud-system design for particular formations, the company has been able in one case to reduce the amount of time to drill a Piceance well from 22 days to 13. In its completions, Laramie, like other basin operators, is using slick water and flow-through plugs for its multi-stage fracs to achieve faster and better flow-back rates and recoveries from its wells. In addition, immediate cost savings are achieved. "Fracing with older polymer gels used to cost $200,000 to $250,000 per frac stage whereas fracing with slick-water fluids today is costing us on average $45,000 to $50,000 per stage," says Schroeder. Shifting focus Formerly focused on oil production in Russia, publicly held Teton Energy Corp.-a Denver-based operator that until recently was known as Teton Petroleum Co.-has also set its sights on the much closer-to-home Piceance Basin. "We believe the basin-centered gas accumulation there has a long way to run, plus the political, commercial and exploration risk in the Piceance is low," says Karl F. Arleth, Teton president and chief executive officer. "In the Piceance, the more proficient an operator becomes technically, the more gas he gets out of the basin and the better the economics then become." This February, Teton purchased-for $5.25 million in cash plus unregistered Teton stock and warrants-a 25% interest in Piceance Gas Resources LLC, a partnership that owns about 6,300 acres in a block just northwest of the basin's Grand Valley Field. Also participating in the partnership are Orion Energy Partners LLC, a private Denver-based start-up headed by Jim Lightner, who formerly ran Tom Brown Inc., and Piceance Gas Partners LLC, a group made up of former McMurray Oil and Westport Resources executives. Orion, which will act as contract operator for Piceance Gas Resources, holds a 50% stake in the partnership; Piceance Gas Partners, a 25% stake. While there's currently no production on the 6,300-acre block, which is a lease purchase from Petroleum Development Corp., the partnership this July was nearing completion on two Williams Fork wells on the acreage. Overall, a minimum of eight Mesaverde wells like these are planned for 2005. "We have the potential, once the entire block is proven up, to downspace to 10 acres," says Arleth. "On that basis, there's the potential to drill about 630 wells on this acreage. And, if one assumes reserves per well of 1.3 Bcf, this means the partnership is looking at exposure to estimated gas reserves of more than 800 Bcf." The total project, he says, will involve three to five years of drilling to prove up all the acreage and another three to five years of infill drilling. With each well costing the partnership about $1.6 million to drill and complete, initial F&D costs should be close to $1.80 per Mcf, says the former Amoco executive. However, he contends that with Orion's experience in the basin, with fracing technology continually getting better and well recoveries continually getting higher, those costs should lower over time. "The risk in the Piceance isn't drilling a dry hole; rather, the risk is all technical," explains Arleth. "Very simply, we have to pay attention to drilling and completing our wells properly, and the better we get at that, the better our economics become. Indeed, it's not inconceivable that we could improve per-well recoveries to between 1.5- and 1.7 Bcf." Like other operators in the basin, the partnership will be drilling clusters of directional wells from single pads as it probes the Mesaverde section, concentrating production and gathering facilities on those sites. "That not only creates a small surface footprint, but also economies of scale in your operations," says Arleth. Additionally, Piceance Gas Resources will be using multi-stage fracs-an average of six to eight per well-in its completions. "Since the wells are clustered, a well-service company can come in and work on fracing more than one well at a time, which lowers costs and allows production to come online faster." The geologist points out that the Grand Valley, Parachute, Rulison and Mamm Creek fields form a west-to-east fairway in the Piceance where the Mesaverde section lends itself to drilling wells on 10-acre subsurface spacing. The Mesaverde, typically occurring at depths ranging from 8,500 to 9,000 feet in this portion of the basin, is a series of vertically stacked, fluvial sandstones which, although they don't have much lateral continuity beyond 10 to 15 acres, are nonetheless 1,500 to 2,000 feet thick, explains Arleth. "That thickness is why a producer can drain a lot of gas-typically 1.3 Bcf per well-out of that section of rock using six-to-eight-stage fracs. If the Mesaverde section were only 200 feet thick, the play wouldn't be commercial."