Both fields are regional, as well as national, gas powerhouses.

The outcome of a Supplemental Environmental Impact Statement (SE IS) for Pinedale released in September has opened up year-round drilling in concentrated areas on the Pinedale Anticline. In Jonah Field, dominant operator EnCana Corp., Calgary, is posting production growth thanks to a sturdy drilling program, rewarding new wells and downspacing. Operators in both areas continue to pare drilling times and costs to further brighten the economics of these top-ranked gas fields.

Bill Lanning, associate field manager with the Bureau of Land Management’s Pinedale Field Office, notes that the operators’ proposal that prompted the SE IS anticipates the drilling of 4,399 wells from 600 well pads to develop the field. Currently, some 984 wells have been drilled on the anticline from 380 pads.

The BLM record of decision (ROD ) issued at press time addressed impacts to wildlife, water and air quality, local and regional socioeconomic values, and other surface concerns. Several measures will mitigate the effects of the anticipated increase in drilling from more pads, and year-round. These include directional drilling of multiple wells from a single well pad, the use of well pads, construction of a liquids gathering system to handle condensate and produced-water transportation, reduction of NO X and dust from truck traffic, and more efficient and cleaner engines on rigs to reduce emissions.

Questar Exploration and Production Co.’s Paul Matheny, vice president for the Rockies region, says the company was careful to have two plans, one the status quo, and one based on the concentrated development and year-round drilling that will occur now that the SE IS decision has been released.

“Industry’s intention is to have a better way of operating,” says Matheny. “Operators won’t be subject to the seasonal closures on the anticline that exist right now. Instead they’ll be working year-round in focused areas, which would be better for wildlife and for air quality. The benefits are for all values and all stakeholders.”

New Spacing, Pipelines

Each company will operate as many rigs within six-square-mile areas as is prudent. For Salt Lake City-based Questar, this would mean from 10 to 15 rigs, rather than the current six rigs in the winter and nine rigs in the summer, directionally drilling up to 32 wells per multi-well pad. Operations will move from the south to the north, reclaiming the majority of surface disturbance to productive habitat immediately after development. This focused drilling scenario will leave 92% of the anticline unoccupied and undisturbed for wildlife.

To accommodate its growing production, Questar is adding a 30-inch pipeline and new gas turbine compression to move gas from the field to its Black Forks plant. These additions are expected to increase transportation capacity by 350- to 400 million cubic feet per day. The line is set for completion in November 2008.

Through the first six months of 2008, the company had stepped up production 9% to 12.5 billion cubic feet equivalent from 11.5 billion in the first half of 2007. Six rigs were running year-round and three rigs were doing delineation drilling in anticipation of the SE IS, to further understand the limits of the field.

“We want to be prepared and confident when we plan the pads so that we know where the wells should be drilled from each pad within those six-square-mile areas, and development can progress through the field from south to north and we don’t need to go back,” says Matheny. Questar was on track to complete about 75 to 78 wells through 2008.

As of mid-August the company had some 290 producing wells, net proved reserves of 1 trillion cubic feet equivalent (as of year-end 2007) and additional net probable reserves of 2.1 Tcf in Pinedale.

Drilling times are on the wane. The efficiencies of the multi-well pads mean rigs can skid 14.5 feet to the next location in a few hours rather than the seven to 10 days it used to take to move a rig. As the company continues to determine which bits work best and crews get more experienced, the average time from spud to total depth (TD ) has dropped to 27 days and to as little as 18 days for some wells.

Reserves per well range from an average 3- to 6 billion cubic feet but can top 20 Bcf.

Questar completed a deep test on the northern end of the anticline in 2005 to about 19,500 feet into Hilliard shale, with extensive testing of the Hilliard and Rock Springs formations. All of the intervals tested initially produced significant volumes of gas but at sustained rates less than the overlying Lance, the main reservoir in the field. The incremental time and cost to drill for the deep formations did not justify the delays that would be incurred in the development of the Lance reservoir, according to Matheny.

Still, the company has upwards of 1,500 additional locations at Pinedale as drilling drops down to five-acre bottomhole spacing.

With the conclusion of the SE IS process, Questar expects to move more of its clean-burning, state-of-the-art rigs to Pinedale from other areas of the U.S., to speed up its program— finishing in 10 to 12 years. With the Energy Information Administration ranking Pinedale the second-largest gas field in the U.S., recoverable reserves are estimated at anywhere from 20- to 25 Tcf, notes Matheny.

Ultra Petroleum enjoyed a 78% increase in the number of wells it drilled in Pinedale in 2008 versus 2007, with 155 operated in 2008 versus 87, respectively. Like other Pinedale operators, Houston-based Ultra believes that after an initial transition period, additional access in Pinedale Field will lead to increased drilling efficiencies and allow for accelerated development, while simultaneously committing to decreasing emissions and implementing measures to further mitigate impact on wildlife.

Sally Zinke, director of exploration, credits the use of oil-based mud, new bit technology, skid rigs, and underbalanced drilling for the faster drilling times achieved by the company in recent years. It has pared its spud-to-TD spans from 30-35 days to an average of 22 days, with some wells in the teens.

“That’s been huge in our ability to get more wells drilled in one year with the same equipment and the same people,” Zinke notes.

More Frac Stages

Delineation drilling to determine east and west expansion of the field has yielded half a dozen wells to date, plus at least 25 more in 2008. These have resulted in reserve growth more than double what was forecast. In the Warbonnet area, four delineation wells brought on production in first-quarter 2008 averaged 12 million cubic feet of gas per day each, with estimated ultimate recovery (EUR ) exceeding the 2007 year-end pre-drill estimates by about 70%.

The company expects its total resource to grow to 14 Tcf equivalent over the next few years.

A deep test to the Hilliard did not result in fracing into a natural fracture system, and Ultra is now testing the Blair.

Another technique Ultra has been using since last year to increase production involves additional frac stages, usually two or three, in low-quality pay below the current sand cut-offs. These result in 100- to 150 million cubic feet of reserves per frac stage at a cost of about $90,000 per frac, adding about half a billion cubic feet per well in the pilot program.

Ultra has used the process in about 48 wells so far in the southern end of the anticline and could expand it into the north.

A ruling in July from the Wyoming Oil and Gas Conservation Commission took most of the core area of the field to 10-acre spacing. Zinke notes that an average well initial production remains at 7.4 million cubic feet per day.

The company has 5,300 additional locations it will pursue over the next two decades. She expects that pipeline infrastructure will move to keep up with developments and forward plans for drilling as those solidify when the SE IS is finalized.

Delineation drilling and production from non-pay sands are key elements in Pinedale’s future, according to Bucking Horse Energy Ltd., based in Vancouver, British Columbia. The company was formed by founding shareholders of Ultra Petroleum and through the merger of Gemini Energy Corp. and NR G Investments Inc. in March 2008. It now holds 14,372 gross acres (approximately 4,000 net) in the field.

Cliff Adams, chief executive officer, notes that its net production is 8.5 million cubic feet per day (Ultra operates), and proved reserves are 101 Bcfe. In the Warbonnet unit, in the fairway, Bucking Horse holds an average working interest of 42% in 2,480 gross acres (a bit more than 1,000 net), with proved reserves of 56 Bcfe.

In the Mesa area to the northeast, its average working interest is 24% and it holds 9, 512 gross acres, 2,328 net, and has proved reserves of 45 Bcfe. Ultra and Anadarko Petroleum Corp. hold the majority of the remaining interests in these areas.

“The productive fairway keeps expanding,” notes Adams. “There is delineation drilling to the east and west, mostly in Warbonnet. In late 2007, the WB #10-D24 IP’d at a rate of 12.7 million cubic feet per day, with the WB #9D-14 well just north of our Warbonnet acreage coming in at an IP of 15.8 million per day.

“This delineation drilling is clearly expanding the sweet spot of the fairway.”

Adams also recounts the potential in non-pay sands. “Only one-quarter or so of the sand in the Lance Formation has been opened, historically. Our understanding is that Ultra has been opening up more non-pay sand and has been getting similar results as the productive pay sands on a finding- cost basis,” says Adams.

The 10-acre downspacing rule changes the reserve category for many wells, and Bucking Horse expects its proved reserves to increase by approximately 30% as a result of the downspacing alone. Only 25% of its overall locations in the proved and probably categories are based on 10-acre spacing.

“The Lance is a fluvial system, with stacked but discontinuous reservoirs, and as a result, little if any communication down to even five-acre spacing,” notes Adams. “The general rule of thumb for the Lance is around 1 billion cubic feet of gas in place per acre, although the average is higher. We have approximately 1,500 net acres which would yield a healthy 1.5 Tcf in place.

“At 60% to 80% recovery factors on 10-acre and 5-acre spacing, respectively, that would give exposure to over 1 Tcfe net to Bucking Horse.” Through the remainder of 2008, based on year-round drilling approval, Bucking Horse is expecting three wells to be drilled on its acreage by the operator. One of the three remaining 2008 wells on the schedule has been spudded in the Warbonnet near the #10D-24.

Jonah

EnCana Corp., the dominant operator in 23,000-acre Jonah Field, operates some 800 wells and has been drilling about 160 wells per year since it received BLM authorization to develop the field in 2006. The field currently produces 650 million cubic feet per day, or 255 billion annually.

EnCana’s production from Jonah during second-quarter 2008 averaged 630 million cubic feet per day, a 20% surge over the same period a year ago.

This year down-dip wells are turning in strong rates with average 30- day initial production (IP) for the second-quarter of 3.5 million cubic feet per day and climbing. The company credits encouraging results from newer wells and continued lower line pressures for the upticks.

Its 2008 goals for the field are to consolidate its gas gathering and production systems and continue 10- acre development while exploring the potential for five-acre well spacing.

The drilling program through 2008 will mirror that of 2007, with 160 wells scheduled for the field. “We are working our plan in a favorable situation,” says Randy Teeuwen, community relations director based in Denver, “but we are always sensitive to the environment and looking for better ways to develop the field.”

In 2005 the Wyoming BLM approved an innovative surface reclamation plan allowing the company to use oak mats to build drilling pads wherever possible. This helps it to avoid scraping off topsoil and it lessens disturbance of root structures.

The BLM ’s record of decision for Jonah is based on the amount of disturbance created, rather than number of wells drilled, with operators limited to a total 14,030 acres of disturbance, according to Teeuwen.

Other environmental concerns include air emissions issues.

‘We are the only operator in the state currently using natural gas-fired drilling rigs powered by gas from wells we’ve drilled,” says Teeuwen. “We’re doing this on 10 rigs which allows us to eliminate 90% of our NO x emissions compared to conventional Tier-one diesel engines. And all are outfitted with iron derrick-men and roughnecks in an automated system. The technology is safety-focused and keeps our drilling workforce out of harm’s way.” The company also uses low-emission dehydrators and cleaner gas compressors.

On the production side, to mitigate volatile organic compounds concerns, EnCana has been reducing gathering system pressure. Former line pressures in Jonah of 600 psi have been cut in half to 254 psi in second-quarter 2008. The company plans to continue reducing pressures over the course of next year.

EnCana is now drilling wells to depths of 12,000 feet in as little as 17 to 20 days with fracing in 8 to 12 zones at various depths in the well bore.

With pipeline capacity out of the Rockies full, EnCana and the other operators look forward to completion of the next leg of the Rockies Express Pipeline (Rex), which is projected to be extended to Clarington, Ohio, by mid-2009.

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