With at least 300 trillion cubic feet of gas reserves yet to be recovered in the Rockies, there's a tremendous opportunity for the industry to step up exploratory drilling efforts in the region. Much of this remaining resource potential, however, can be found in fields that have already been discovered and that are already producing. Indeed, independents are beginning to realize that many existing fields have the potential to yield not only higher volumes of production from known hydrocarbon-bearing strata, but also new reserves in overlooked formations above or below these strata. "Field rejuvenation has been a big part of our value creation over the past five years," says Jim Lightner, chairman, president and chief executive officer for Denver-based Tom Brown Inc. In fact, excluding initial acquisitions, field rejuvenation has accounted for about 30% of the company's total organic growth in gas volumes during the period. "It's a lot easier and more economic to go out and find gas in older fields-where it has already been found-than to find new gas fields," he says. This isn't to say that Tom Brown doesn't have an active exploration program throughout the Rockies and elsewhere, including the Deep Cotton prospect in East Texas. "We've simply found that putting together integrated teams to conduct extensive analysis and reservoir characterization of older fields can lead to both enhanced recoveries and new reserve additions." Lightner's use of the phrase "enhanced recoveries" may be something of an understatement, based on some of Tom Brown's recent successes in the Rockies. James A. Honert, Rocky Mountain exploration manager for Tom Brown, notes that in the case of the company's Pavillion Field, in Wyoming's Wind River Basin, extensive field rejuvenation there ballooned gas production from less than 1 million cubic feet per day at one point in the early 1990s to a peak of 60 million cubic feet per day in 2002. Similarly, at Andy's Mesa in southwestern Colorado's Paradox Basin, the company increased daily gross gas output from under 2 million cubic feet in mid-1999 to 36 million cubic feet today, while growing the field's reserves from a gross 25 billion cubic feet (Bcf) to more than 100 Bcf. Says Honert, "In each case, teamwork more than technology has been the key to growing reserves and production." Pavillion Field Located in the middle of the Wind River native American reservation in central Wyoming's Fremont County, the 44-year-old Pavillion gas field was acquired by Tom Brown from Shell in 1986. "Initially, we experienced some voluntary curtailment-80% of some 7- to 8 million cubic feet per day of gas production was shut in from some 40 wells-due to low-priced contracts and the lack of adequate marketing facilities," explains Corky Vickers, operations engineer. "However, in 1992, we acquired control of gas-gathering and -processing infrastructure in the region, which opened the door for economic development of the field." By 1995, the company had drilled 10 infill wells and finished five behind-pipe recompletions in Pavillion, which pushed gas production there up to 27 million cubic feet per day. Five years later, though, daily output slipped to 23 million cubic feet. "That's when we began a fully integrated team approach to unlock this field's real potential," says Vickers. The team, comprised of as many as 23 geologists, reservoir and drilling engineers, land, regulatory-support and field staff over the course of the project, began a rigorous evaluation of all existing data. This data included many drill-stem tests run on the original wells. "A couple of things jumped out at us from these tests," says Ray Johnson, reservoir engineering advisor. "The 'skin factor' or degree of damage to the producing formations-the Upper Wind River between 1,300 and 3,000 feet and the Fort Union between 3,600 and 5,800 feet-was greater than zero, which meant these zones had damage and could be stimulated." Johnson points out that when Shell began drilling the field in the early 1960s, on 640-acre well spacing, it didn't fracture-stimulate many of the producing zones. Most were either just perforated, or perforated with an acid job. "We also noticed from studying the gas rates on those drill-stem tests that many of the high-rate zones in the original 40 wells were never completed," says Johnson. "That meant the added opportunity of developing productive zones behind pipe." Analysis also revealed that the Upper Wind River and Fort Union would be most effectively drained by drilling wells as closely spaced as one per 20 acres. That's not all the analysis revealed. "Most of Shell's development of Pavillion through 1985 was from the 3,300- to 3,400-foot Basal Wind River formation," explains Bill Hobbs, senior geologist. "When we acquired this field, there was all this Fort Union and Upper Wind River pay with which Shell had only dabbled." Challenging, however, was the fact that Shell drilled the field's original Fort Union wells using oil emulsion to minimize skin damage. That emulsion makes log analysis very difficult, says the geologist. As a result, only a very basic framework of stratigraphic correlation was established within the field to see how sands relate to one another, from well to well. "This meant we had to come up with a good petrophysical analysis that allowed us to tell what was pay versus what wasn't, which sands would produce gas versus water, then correlate that data to the sands in the existing Shell wells," says Hobbs. "Eventually, we were able to put together a geological framework that essentially told us where on the structure we should drill our development wells." Following this integrated analysis and reservoir characterization, Tom Brown, from December 2000 to April 2002, drilled 54 new Pavillion Field wells, nine recompletions and 18 workovers on roughly 40-acre spacing agreed to by the Bureau of Land Management and the Wyoming Oil and Gas Conservation Commission. Pavillion gas production grew from 23 million cubic feet per day to a peak of more than 60 million per day. "At the same time, we grew the estimated ultimate recovery of reserves in the field from 143 Bcf to more than 328 Bcf," says Darrin Henke, southern asset manager, Rocky Mountain division. To handle the increased gas production, the company added 5,925 horsepower of compression and 13,500 feet of looped or parallel-line gathering systems in the field. Notably, during this stepped-up phase of activity at Pavillion, the company was able to reduce the average cost of drilling a new well, from $420,000 in 2000 to $269,000 in 2002. Meanwhile, the number of days it took to drill a well fell from 15 to seven. "One of the ways we achieved these increased efficiencies was by instituting performance bonuses," says Henke. "The faster the crews drilled the wells-without a lost-time accident-the greater their bonus pay." Tom Brown also saved both time and money drilling its wells by using polycrystalline diamond cutter (PDC) bits. "With these bits, we were able to get wells drilled using just one bit; there was no tripping in and out of the hole to change bits. "Also, in 2000, we started using two hydraulic pumps on our rigs, instead of one, to move the drilling fluids and drilling mud through the wells. That also helped us drill faster and keep the wells clean." In a move aimed not at improving drilling economics, but leaving a lighter environmental footprint, the company went to closed-mud systems for its wellsites. This meant reserve pits for storing and circulating drilling mud didn't have to be constructed in an irrigated-crop environment where surface-owners wanted no part of such pits. "We weren't obligated by any regulatory statute to do this, and it initially added $10,000 to $20,000 to our per-well costs," says Henke. "But the move is consistent with our goal to minimize surface damage, to tread lightly." On the completion side, the company also managed higher levels of efficiency, reducing the number of days it took to complete a well from 48 to 12. "Initially, we were only averaging two or three completion stages-each stage being a perforation and a frac-per well," Henke explains. "By 2002, however, we were averaging 6.5 completion stages per well. This means we were adding a lot more pay per well while cutting by 75% the number of days spent to complete each well." The company also went to rigless completions, which use wireline and specialized equipment without a rig to perforate and frac all of a well's productive zones. In the area of recompletions, which focuses on going after new zones in an existing wellbore, the producer also managed to prune costs, from $500,000 per well in 2000 to $292,000 in 2002. Importantly, during that same time, it boosted initial daily gas production per recompleted well from an average 1- to 1.5 million cubic feet to 4.75 million cubic feet. Says Henke, "None of this involves rocket science-just persistent, patient teamwork." Andy's Mesa Another Rockies-focused field-rejuvenation project initiated by Tom Brown centers on Andy's Mesa in southwestern Colorado's Paradox Basin. There, the company has pursued the same interdisciplinary strategy used at Pavillion to coax gas output and unlock overlooked reserve potential. When it purchased Andy's Mesa from Unocal in 1999, the field was producing less than 2 million cubic feet of gas per day from just a couple of its eight wells; the estimated ultimate recovery of the field's gas reserves, meanwhile, was estimated at 25 billion cubic feet equivalent (Bcfe), says Dean Liley, northern asset manager, Rocky Mountain division. "Since cumulative gas output in the field had already reached 24 Bcfe, most people thought of it as just another P&A (plug and abandon) liability." Tom Brown wasn't one of them. "Among the first steps we undertook was evaluating existing 3-D seismic data on the field that had been shot and shelved," says Liley. "This helped us realize that the reservoir there was much more complex than had previously been thought. "When we combined that with reservoir characterization and drainage studies, we came to the conclusion that the field's wells hadn't drained nearly as big an area as many thought. This meant there were not only a lot of remaining opportunities for infill drilling, but also for field-extension drilling." Between 1999 and May 2003, the company drilled 25 infill and field-extension wells-targeting the 5,000- to 9,000-foot Honaker Trail and Cutler formations-with average drilling and completion costs running about $1.5 million per well. The result: the field is now producing 36 million cubic feet of gas per day while the estimated ultimate recovery of reserves there is now 110 Bcfe. Adds Liley, "Since we produce 2.5 to 3 Bcf per well at Andy's Mesa, our finding and development costs there are around 70 cents per thousand cubic feet. For an investment of $1.5 million per well, that's a pretty lucrative return on our investment." Fuller Reservoir A Rockies field-rejuvenation project Tom Brown hopes to talk glowingly about down the road is one it's now embarking upon in the Fuller Reservoir Field, some 20 miles southeast of its Pavillion Field success. While the field has a history of shallow oil production, many nearby wells have yielded sporadic and widely distributed gas production with a wide range of deliverability, according to Honert. Tom Brown conducted a detailed study of the field following its acquisition in May of all the potentially gas-productive horizons in the field-including the Fort Union and Wind River horizons- from Petroleum Resource Management. The study led Tom Brown to believe that an advanced understanding of the field's reservoir, infill drilling and completions could net big increases in both production and reserves. The company plans to drill and complete six wells this winter, each at $950,000, to evaluate the gas-productive potential of the 3,500- to 7,000-foot Lower Fort Union formation. "In addition, we've already acquired 3-D seismic over a portion of the prospective area, which should help us plan future drilling operations," says Honert. "Right now, we're just at the evaluation stage in what we hope will be a successful field-rejuvenation project." He adds, "We're not going to walk away from Fuller Reservoir until we fully understand and exploit all its upside. The way you accomplish that? You just roll up your sleeves."