Just south of the Uinta Mountains-a 150-mile-long succession of geological anticlines and synclines that takes an unusual east-west path through northeastern Utah-lie the high plains, rolling valleys, buttes and mesas of the Uinta Basin.

In prehistoric times, the "welcome-wagon" committee in this neighborhood was comprised of Tyrannosaurus Rex, Stegosaurus and Allosauraus-dinosaurs that took "eating out" very seriously.

These daunting denizens of the basin may be long gone. But until just a few years ago, many newcomers to the Uinta-wanting to drill for natural gas-still didn't feel terribly welcome. Indeed, with gas prices depressed to levels below $1 per thousand cubic feet (Mcf), they may well have felt like fossil fools.

That, too, seems like ages ago. Thanks to the dramatic improvement in oil and gas prices and the added gas-takeaway capacity provided by the new Kern River Pipeline, Uinta Basin operators now realize an average $4 to $5-plus per Mcf for their natural gas output.

Meanwhile, an even more important trend is taking shape: North American producers, large and small, are flocking to the Rockies-leasing large parcels of gas-bearing acreage or buying out Rockies operators that already have such holdings and the expertise to drill them.

Without a doubt, more such consolidations are contemplated. (See "Mountain Merger Mania," Oil and Gas Investor, July 2004.)

Small wonder. The Rockies represent the last great onshore frontier in North America for natural gas exploration and development. By various estimates, there's anywhere between 279 trillion cubic feet (Tcf) and 346 Tcf of remaining gas-resource potential in the region-much of this in unconventional tight-sand gas and coalbed-methane (CBM) plays.

The Uinta Basin itself, with an estimated 30.7 Tcf of remaining gas-reserve potential, is one corner of the Rockies where operators are increasing their drillbit focus. Already large firms such as Questar Market Resources, EOG Resources and Dominion Resources, alongside smaller producers like Gasco Energy and Berry Petroleum, are rethinking their strategies in the region.

Armed with the ability to more efficiently drill and complete Uinta wells, they're beginning to look past the shallow Green River and Wasatch formations-scrutinizing the deeper Mesaverde and Blackhawk horizons for their gas-bearing potential.

Higher Prices, Deeper Plays

The entry of Houston-based EOG Resources into the Uinta Basin began in 1984 with its acquisition of Belco Petroleum Corp.'s Rockies assets-a purchase that also included significant holdings in Wyoming's Greater Green River Basin. Since then, the company's primary focus in the Uinta, where it holds more than 100,000 net acres, has been the greater Natural Buttes gas play.

"Through the 1990s, we focused on that play's shallow, gas-bearing horizons in the Wasatch formation-typically at depths between 7,000 and 8,000 feet-enjoying a 90% drilling success rate," says EOG vice president and general manager Kurt D. Doerr, who oversees the company's upstream Rockies activities from Denver.

"We initially stayed shallow in the play because one couldn't afford to drill deeper due to the associated costs and low gas prices-below $1 per Mcf at the time," explains Doerr.

With the improvement in gas prices in the past few years, however, and some exploration by EOG and others in the Natural Buttes area, the company has started to exploit the play's 8,000- to 11,000-foot Mesaverde formation, finding very large potential beneath the Wasatch.

Since 1984 EOG has produced about 180 billion cubic feet (Bcf) of gas from the nearly 600 Wasatch wells it operates in the Natural Buttes area. Now it estimates the stacked, fluvial sands of the Mesaverde may contain another 200- to 400 Bcf of gas-reserve potential, net to EOG. With this treasure trove in mind, the producer has boosted its 2004 capex budget in the Uinta, to about $55 million versus some $30 million last year. While a portion of its spending this year is earmarked for drilling 30 more Wasatch wells, the bulk of its expenditures is slated for drilling 60 Mesaverde wells. Comparatively, EOG drilled 47 wells in the Uinta in 2003, most to the Wasatch.

"Since our ramp-up of drilling and compression in the Mesaverde since the beginning of 2004, we've actually seen a 20% growth in net production-to 40 million cubic feet per day-from September 2003 levels," says Doerr.

Doerr emphasizes, however, the company is just in the early stages of tapping the basin's deeper-horizon gas potential. He notes that EOG has recently initiated an environmental impact study (EIS) on its part of the Natural Buttes area, with the aim of drilling an additional 600 wells to the Mesaverde during the next five to 10 years.

As it moves forward with deep and shallow drilling in the Uinta, the operator is keeping a sharp eye on reducing drilling costs and improving operating efficiencies. "In 1959, one of the first wells drilled in the Uinta took 110 days and 78 bits to reach a total depth of 10,150 feet," says Doerr. "Today, EOG can drill to 10,800 feet in 18 days using only three or four bits."

In its Uinta drilling, the company uses polycrystalline diamond cutter (PDC) bits that allow an operator to drill faster with fewer bit changes. Simply, not as much time is spent as in the past on tripping in and out of the hole to change bits, saving money.

Through bit selection and other improvements in drilling technology, EOG has been able to shorten drilling time by about 15% since June 2003, which translates into savings of $40,000 to $45,000 per well. "When you spread that kind of savings out over a 90-well drilling program, that adds up to total annual cost savings of $3.6- to $4 million," says Doerr.

For well completions, the company has been using multi-stage fracs to further reduce costs and enhance production. "While this is commonplace today, we started it a long time ago and have refined the process."

Currently, a typical Wasatch gas well in the Uinta costs the operator just under $600,000 to drill and complete; the cost of a Mesaverde well, meanwhile, runs $1.1- to $1.4 million, depending on depth.

These gas wells typically start out flowing 1- to 1.5 million cubic feet per day, but their daily production rates will decline fairly quickly-leveling out at 400,000 to 500,000 cubic feet for quite some time before ultimately falling off to 20,000 to 30,000 cubic feet per day. "The good news is that these wells will typically produce for more than 40 years," says Doerr.

Also good news for EOG is that it's well positioned in the Uinta for the sale of its gas production, which can move into Northwest Pipeline, Questar Pipeline or the Colorado Interstate Gas (CIG) line.

Blackhawk Bounce

Five years ago, Englewood, Colorado-based Gasco Energy Inc., a then-private start-up, realized two things about the Uinta Basin: its gas potential was largely underdeveloped, but its prolific Natural Buttes region on the east side of the Green River was already dominated by giants such as Questar and EOG Resources.

Recognizing the Green River was only a geographical, not a geological, boundary, the company turned its focus to the less active west side of the river. There it felt a small operator could more easily put together an acreage position to tap the same gas-bearing formations that were being drilled on the river's eastern side.

Thus in 1999, about 10 miles southwest of Roosevelt, Utah, it began assembling what today is about 71,500 net acres in the Riverbend, West Desert, Wilkin Ridge and Gate Canyon areas-not coincidentally, right along the route of Questar's 20-inch pipeline that ties into the Kern River Pipeline.

In April 2001, around the time it went public on Nasdaq under the symbol GASE, Gasco spudded the first of 16 wells it has drilled in the region through mid-2004, principally in its core Riverbend area. The gas wells, all successful, originally came onstream flowing 1- to 1.5 million cubic feet per day. Today, they're coming on at 2- to 2.5 million cubic feet per day.

Gasco's current reserve base is 21 billion cubic feet (Bcf), which includes a first-quarter 2004 acquisition of reserves and production from ConocoPhillips.

"Most of these wells, exploitation in nature, have targeted the 6,000- to 8,500-foot Wasatch and the 8,500- to 12,000-foot Mesaverde formations," explains Michael K. Decker, Gasco's executive vice president and chief operating officer. "But now, in more of an aggressive exploitation mode, we're beginning to target the deeper Blackhawk formation below 12,000 feet. This is the real exciting part of the play-where the real gravy is."

In contrast to the Wasatch and Mesaverde, whose sands are lenticular or discontinuous in nature and therefore hard to track, the Blackhawk formation is more of a linear-trend play, which makes it easier to predict prospective locations.

In mid-June, the company announced that its Wilkin Ridge 12-32 well, a 13,200-foot Blackhawk test, was commercial, flowing at an initial rate of 2.1 million cubic feet per day. This followed a smaller Blackhawk discovery by Gasco in March.

"Without any contribution from the Blackhawk, we were already achieving around 20% rates of return on our wells," says Decker. "The significance of the Wilkin Ridge discovery is that it adds 2.1 million cubic feet per day of gas to our production from the Blackhawk alone-and we still have the Mesaverde to complete in that wellbore. Put another way, the Blackhawk could add another 1 to 2 Bcf per well."

Echoes Mark Erickson, Gasco's president and chief executive officer, "By adding this new producing horizon across parts of our Uinta leasehold, we have the potential to significantly improve well economics and accelerate reserve additions."

Ideally, Gasco would like to turn this play into a manufacturing process, like a lot of other tight-sands gas plays in the Rockies. Its 2004 capex budget is $13 million, up from $3- to $5 million spent last year, with plans to drill up to 15 gross Uinta wells.

"Our goal and that of our partners is to also bring our finding and development costs down from around $1.50 per Mcf to below $1. With the addition of Blackhawk production-and improved economies of scale due to increased activity-we believe this goal is achievable."

Backyard Fit

For Questar Corp., the Salt Lake City-based diversified energy giant, the Uinta Basin has been familiar turf since 1960 when it gained a federal unit-holding in the region. But it wasn't until 2001 that Questar Market Resources-which controls all of the firm's non-regulated business activities, including E&P-made a big splash in the basin's greater Natural Buttes area with its acquisition of Shenandoah Energy Inc., a private Denver operator.

The purchase gave Questar 118,000 net acres and 415 billion cubic feet equivalent (Bcfe) of proved reserves. Daily operated oil and gas output was 3,400 barrels and 50 million cubic feet, respectively, from 330 producing wells. In addition, it acquired 90 miles of gas gathering lines and a 100-million-cubic-foot-per-day gas-processing plant.

"Being a Utah-based energy company with interstate pipeline infrastructure in the Rockies and a natural gas utility serving some 750,000 customers in the region, we were looking for a large inventory of development-drilling opportunities nearby," says Jay B. Neese, vice president of Questar Exploration and Production Co. in Denver. "The Shenandoah acquisition gave us a lot of synergies with these regulated businesses."

Chuck Stanley, Salt Lake City-based president and chief executive officer of Questar Market Resources, adds: "What we like about our Uinta position is that there's a lot of operating efficiency from having all these upstream assets in a tightly concentrated area. Also, it's a play that's low-risk and very repeatable.

"We have identified more than 150 Green River, Wasatch and upper Mesaverde proved undeveloped (PUD) oil and gas locations left to drill in our inventory-at depths ranging from 3,000 to 9,500 feet. But there's also lightly explored, deeper potential in the lower Mesaverde, Blackhawk and Mancos formations, from 9,500 to 13,000 feet."

Since the Shenandoah buy, Questar has drilled 250 wells on its Uinta acreage, reporting a 90%-plus success rate. It has primarily targeted Green River, Wasatch and Mesaverde gas in its Red Wash, Wonsitts Valley, Glen Bench, White River and Gypsum Hills field units.

"This effort caused our operated gas production to increase to a peak level of 100 million cubic feet per day in 2002," says Mike Collom, Uinta Basin production and operations manager for Questar Exploration and Production in Denver. "More recently, however, daily operated gas output has been averaging 80 million cubic feet. Still, that's up from a low of 69 million cubic feet in late 2003.

"What this says is that we're not only offsetting the decline rates in older wells but are actually beginning to grow production again, even with fewer rigs running. That's due to drilling more efficiently and to better completions."

Neese notes that Questar has lowered the cycle time from spudding a well to rig release such that the company can now drill an additional 1,200 feet to include upper Mesaverde pay zones-in virtually the same amount of time it used to take to drill just to the Wasatch. "As a result, we're adding an average 300 million cubic feet of gas reserves per well without having to spend substantially more drilling dollars."

Stanley says incremental reserves per well are greatly helping to enhance field economics. "Today, our net finding and development costs for a Wasatch/upper Mesaverde well in the Uinta are right around 80 cents per Mcf."

The use of multi-stage frac technology allows the company to more efficiently isolate and stimulate as many as six or seven productive zones in a formation, then drill out the frac plugs and commingle the flow from these zones-in just two days.

"With this technology, we're recovering probably 60% more gas from an average well than we previously did using single-stage fracs. The important point here is that by recovering more gas quicker, we're accelerating the present value of our cash flows," Stanley says.

E&P is the primary net income generator for Questar Market Resources, but the midstream division, Questar Gas Management, is also making a growing contribution to net income, primarily from its expanded gas gathering, processing and transportation services to third-party producers in the Unita Basin and elsewhere in the Rockies. Notably, during the 12-month period ended March 2004, more than 70% of Questar's companywide net income-from regulated and unregulated operations-has come from Questar Market Resources.

Turning to the Uinta's often overlooked oil potential, Neese says his E&P group is earmarking part of its $50-million Uinta Basin capex budget for waterfloods in five fields in the Natural Buttes area. "After 50 years of production, only 16% of the original oil in place in the Uinta's Green River formation fields has been recovered; comparatively, oil recoveries in similar fields elsewhere are 30% to 35%."

Overcoming Rising Costs

Dominion Resources' first foray into the Uinta was in 1993 when it partnered with River Gas, a small private independent, on a CBM development project in the Drunkards Wash area of Carbon County.

But the big entry into the basin for the Richmond, Virginia-based diversified energy giant came in 2000 when it acquired Consolidated Natural Gas (CNG) and its 150,000 net acres of tight-sands gas assets in the Riverbend play in the Natural Buttes area of Uintah County.

"When we purchased CNG, we got 50 to 60 Bcf of proved gas reserves and 300 wells that were producing an aggregate 20 million cubic feet per day of gas from the Wasatch and Mesaverde," says Ronnie K. Irani, senior vice president and general manager for Dominion's western upstream business unit in Oklahoma City.

"What we saw at the time was the opportunity to use our expertise in tight-sands gas operations gained elsewhere in the U.S. to do a lot of concentrated infill, low-risk, development drilling in the Uinta. We also believed that once we gained a large enough property base in the region, we would be in a position to make further acquisitions longer-term."

Since 2000, Dominion has drilled more than 80 infill wells inside the producing Riverbend-achieving a 94% success rate as it tapped, often on a commingled basis, the Wasatch and Mesaverde. The result: 30 million cubic feet per day more gas production and the booking of another 140 Bcf of net proved gas reserves.

This year, the company's capex budget for drilling here will be $60- to $65 million, up from around $34 million in 2003, as it moves forward with a 75-well program-about double last year's effort.

"Our plan is to step out on the periphery of our Riverbend acreage to see if we can extend the limits of our producing reservoirs, hence we'll be doing some extensional as well as infill drilling," Irani says. "If our estimates are correct, we should exit 2004 with Riverbend daily gas output in the range of 70- to 75 million cubic feet, up from a recent level of around 50 million cubic feet."

Currently, Dominion holds rights on some 70,000 cubic feet per day of firm gas takeaway capacity on several pipelines near Riverbend, including the Panhandle Eastern, Questar and Kern River lines. During the past 12 months, it has averaged $4.30 to $5.60 for its Uinta gas, depending on the line used.

Like other cost-conscious operators in the basin, the company is using PDC bits to increase downhole penetration rates and reduce the average number of days it takes to drill a well-from 10 days to six or seven in its case. That's almost an operating imperative given that daily rig rates in the basin have risen 14% from last year.

For its completions, the company also uses multi-stage fracs to get wells online quickly. Using wireline technology, it sets plugs and perforates individual zones almost immediately after a frac or stimulation treatment, then moves sequentially uphole very quickly to perforate and stimulate the remaining productive intervals in a well-all in one operation.

"By doing these fracs, we're able to save three to five days bringing our wells on production," says Irani. "When you're drilling 75 Uinta wells, that adds up to a lot of days of additional production and higher rates of return over the life of these wells. This is very meaningful when the average cost to drill and complete a Uinta well is running $850,000 to $900,000."

The Riverbend play isn't Dominion's only productive muscle in the basin. The Drunkards Wash CBM gas play the company took a piece of in the early 1990s has turned into a tidy little manufacturing operation in which Dominion still owns a 30% working interest.

This play, now operated by ConocoPhillips, with ChevronTexaco another interest-holder, has produced more than 400 Bcf since discovery in 1993-and still has another 600 Bcf of gross reserves remaining in the 1,500- to 3,000-foot Ferron Coal formation.

Although nearly 500 wells have been drilled in the field and gross gas production has already peaked at around 200 million cubic feet per day, Drunkards Wash is still expected to average around 150 million cubic feet of daily output this year. Says Irani: "That means an added 45 million cubic feet per day of net gas production to us."

Recompletions Reap Returns

For Bakersfield, California-based Berry Petroleum Co., the move into the Uinta Basin in late August 2003 was a logical outgrowth of its desire to diversify away from its California heavy-oil commodity base, to lighter oil and natural gas.

In the Brundage Canyon area, 15 miles due west of Monument Butte, the company found both when it acquired from The Williams Production Co. some 43,000 net acres, including 8.7 million barrels of oil equivalent (BOE) of proved reserves. Daily production was 1,300 barrels of oil and 4.5 million cubic feet of gas from 85 wells.

"Our primary objective in this region is the Green River formation, which has five prospective oil and gas horizons ranging in depth from 1,300 to 5,500 feet," says Logan Magruder, Denver-based senior vice president for Berry's Rocky Mountain and Midcontinent E&P operations. "We feel very comfortable operating here since the Berry team in Brundage Canyon is comprised of many ex-employees of Barrett Resources, which owned and operated the field prior to Williams."

Comfortable, indeed. Within just 18 days of acquiring the Brundage Canyon properties, Berry had two rigs running which by year-end 2003 drilled 26 wells in the field. Thus far this year, the company has drilled another 26 wells there. Berry booked another 1 million BOE of proved reserves in the field at year-end 2003 and has almost tripled daily production, to 4,200 barrels of oil and 9.2 million cubic feet of gas.

"Our strategy is to gear about 60% of our capital budget to converting proved undeveloped (PUD) reserves to the proved developed producing (PDP) category; the remaining 40% of our capex is aimed at expanding the productive limits of the field by targeting probable and possible reserves," says Magruder.

This year Berry expects to triple last year's spending in Brundage Canyon, to around $45 million, drilling and completing 55 new wells. It will also work over or recomplete another 40 to 50 existing wells.

Recompletions are an important component of Berry's plan for growing the field's output. Using the latest high-resolution, thin-bed logging techniques to identify previously bypassed zones that were once considered unproductive, the company has been able to re-enter and convert three-barrel-per-day oil wells into 45-barrel-per-day wells at economic multiples.

Whether reentering existing wells or completing new ones, Berry focuses on the latest frac technology to enhance production and cut costs. It uses composite plugs, set at various downhole intervals, which allow an operator to isolate specific productive zones for stimulation treatment during a multi-stage frac operation. These can be drilled out quickly when the operator is ready to recombine and flow back the fractured zones.

"With these plugs, we're able to execute up to six separate fracs in just one day compared to the several days it used to take to complete just a two- or three-stage frac," says Magruder. "So we end up not only saving money but also opening up more reservoir for productive pay."

Recognizing it will soon be operating 150 wells in Brundage Canyon, Berry has hired its own personnel to monitor the field's production, with one person specifically assigned to finding ways to optimize daily output. Previously, field surveillance was handled by contractors. By taking these steps, the company has optimized field output nearly 5%.

These cost-pruning and production-enhancement measures are sorely needed, says Magruder. "With casing and tubing costs escalating 200% during the past six months-and other well-construction costs on the rise-we need to create every efficiency we can to keep our total drilling and completion costs at $630,000.

"As we see it, the ability to hold operating costs just flat in a rising cost environment is in itself an accomplishment."

Although Berry's current production mix is 75% oil, 25% gas, "we expect this to change in the future as we begin to explore the field's deeper, gas-rich Mesaverde horizons."