Reinventing Wattenberg

Anadarko and Noble Energy Inc. are enthusiastic about the new White Cliffs Pipeline that connects Wattenberg crude to Cushing, Oklahoma, for the first time. Here, White Cliffs’ holding tanks loom against the Colorado sky.

When Amoco geologist Roger A. (Pete) Matusczcak worked up the prospect for Wattenberg Field in 1970, based on his work in the San Juan Basin, he no doubt hoped for a sizeable resource. But he couldn’t have predicted the massive workhorse that emerged. The nearly 3,000-square-mile field has produced more than 3 trillion cubic feet (Tcf) and 400 million barrels of oil. And it’s not done yet, with an estimated 5 Tcf ultimate recovery in its tight-sands formations. Current production is about 550 million cubic feet and 50,000 barrels daily.

Cory Eikenberg, one of Anadarko Petroleum Corp.’s Wattenberg production supervisors, has made a career in the field since he was 19. When told that Matusczcak, the field’s discoverer, was being interviewed for this story, he said, “Tell him I said ‘thanks.’”

Today, Wattenberg’s operators like to say the basin-centered, tight-gas field, characterized by high temperatures (250 degrees F) and low-permeability (less than 0.015 millidarcy), is constantly reinventing itself. They say it just keeps on giving…that it has nine lives. They fondly refer to it as an Energizer Bunny.

And today, the field’s production keeps taking them higher, despite crashing rig counts and low natural gas prices. Bentek Energy Inc. expects production in the field to decline by only 1.8% in 2009.

The recently completed D-J Basin Lateral Pipeline offers a new outlet for NGLs to the Overland Pass line.

Wattenberg’s drivers are its low-cost, low-risk shallow drilling targets; 20-acre downspacing; evolving fracture-stimulation technology; ready markets along Colorado’s Front Range; and—notably in the current commodity-price environment—significant oil production, depending on horizons plied.

Wattenberg’s environs are relatively densely populated north and east of Denver and along the Rockies’ Front Range, primarily in Weld, Adams, Boulder, Broomfield and Larimer counties. Operators have been quick to accelerate the net present value of the field, which offers lucrative oil-to-gas ratios. Often, they are in a race to drill ahead of the many suburban housing projects.

“We’re constantly looking at how we can increase our activity levels, reduce inventory and monetize it as quickly as possible,” says Noble Energy Inc.’s David Larson, vice president of investor relations.

Decade by decade, Wattenberg has grown up, pacing industry’s technology strides. Companies such as HS Resources, Basin Exploration, Patina Oil and Gas, Prima Oil and Gas and more made fortunes here and sold out, thriving at natural gas prices that recall today’s postings. It’s evolved from Sussex and Shannon conventional oil production and J-Sand gas in the 1970s, to the 1981 discovery that set off the unconventional Codell fest, to the Codell refracings that gave new life to wells in the mid-1990s, to downspacing rules in 2002 and 2005, to Niobrara recompletions in ’02 that added another course, to the kick-off of Codell tri-fracs in ’05 and today’s horizontal tests in Niobrara. The play has had at least nine lives.

Facing page: Pipe racks await action at the Nygren #5.

The most recent iteration—horizontal drilling—has yielded mixed results, and some operators have kept results close. Noble Energy completed its first effort early this year, while Anadarko reported that its second horizontal, also completed in the first quarter, had an initial potential (IP) rate of 1.2 million cubic feet and 80 barrels of oil per day.

Noble Energy, Anadarko, EnCana Oil & Gas (USA) Inc., Petroleum Development Corp. and Petro-Canada, which is merging with Suncor, owner of one of the two main refineries taking Wattenberg crude, are the mainstays. As in other basins, operators have laid down rigs, and the field’s rig count has fallen from 33 in March 2008 to 18 today.

But like bees in a hive, Wattenberg managers just fixate instead on the plentiful other jobs to be done—10- to 15-year drilling inventories offering a seemingly endless supply of recompletions, and more fracs than you can shake a stick at. A $250,000 refrac of the Codell formation can restore production to close to IP levels. A couple of years later comes the tri-frac.

The liquids production in Wattenberg supports the field’s economics, especially in times of faltering natural gas prices.

In a first-quarter 2009 earnings call, Dave Stover, president and chief operating officer of Noble Energy, described Wattenberg’s portfolio role: “…we are adjusting our activity levels based on commodity prices and focusing most of our (U.S. onshore) drilling activity on projects with a nice contribution of liquids production,” he said.

“... Production from our largest onshore asset, Wattenberg, was up 3% from the first quarter of 2008, despite the impact of a third-party processing plant fire, which reduced our volumes nearly 1,000 barrels equivalent per day in this quarter. …in Wattenberg, we saw record production in the last week at more than 280 million cubic feet equivalent per day.”

Added Chuck Davidson, Noble Energy’s chairman and CEO, “I would say that fields like Wattenberg have huge amounts of excess value over book value.”

The senior-citizen field earned mention by Anadarko’s chief operating officer Al Walker in the same breath as the toddler Marcellus shale. “Both will be the primary beneficiaries of additional capital, even in this downturn. …”

The White Cliffs of Wattenberg

An Anadarko gas wellhead sits beside a golf course in Weld County.

With oil closing on $70 at press-time, leading field operators Noble Energy and Anadarko were enthusiastic about their brand-new, twin oil-polishing facilities steps away from the White Cliffs Pipeline that began filling with crude May 1 and was to begin transport June 1. The project hooks up Wattenberg oil with Cushing, Oklahoma, for the first time, at a capacity of 30,000 barrels per day. Both operators have subscribed to 10,000 barrels daily.

“There have been times when we had to shut in wells up to a week at a time because the area lacked sufficient refining capacity,” says Anadarko’s facilities engineer Joe Aucoin, from his office at the White Cliffs’ connect near Plattesville. “It’s huge for us.”

Price realizations in the field could improve by as much as $6 per barrel thanks to cost efficiencies from the new pipeline, according to Anadarko. Field-wide, savings are a potential $65 million per year at the pipeline’s capacity, according to Wood Mackenzie.

White Cliffs will not only provide producers such as Anadarko and Noble Energy with access to more markets and potentially higher prices for their crude, but also the oil-polishing facilities reduce costs previously incurred in hot-oiling at the individual lease sites. Other benefits: fewer shut-in wells from take-away constraints, reduced air emissions from truck traffic, and an onsite centralized truck facility.

Describing Wattenberg Field’s benefits, Cory Eikenberg, one of Anadarko Petroleum Corp.’s production supervisors, says, “It’s not like drilling a wildcat here. It’s guaranteed.”

Operators were also anticipating significant increased take-away capacity for natural gas liquids (NGLs). The D-J Basin Lateral Pipeline, which began operations in March, is a 125-mile NGL line connecting the D-J Basin with the Overland Pass Pipeline running from Opal, Wyoming, to Conway, Kansas. The latter’s capacity is 55,000 barrels per day from existing natural gas processing facilities in the D-J Basin, among them DCP Midstream’s Lucerne and Mewborne plants. Additionally, DCP’s Platteville and Greeley facilities are connected to Mewborne. The 760-mile Overland line can transport 110,000 barrels of NGLs per day. Increasing NGL production in the Rocky Mountain region correlates with increasing gas development.

“With the Overland and D-J Lateral in place, take-away constraints are lifting for producers,” says Roz Elliot, director of public affairs for DCP Midstream, Denver.

This will provide a valuable additional outlet for NGLs from the field, says Ben MacFarlane, NGLs analyst with Bentek Energy. Previously, the field’s NGLs had to travel on the Phillips Petroleum line down to Borger, Texas, or be trucked to alternative markets in Kansas.

The Wattenberg area’s intense land use—whether urban or agricultural—and air, water, noise and other regulations dictate that environmental best practices be a constant focus for operators. And the drilling footprint is shrinking.

Pad drilling and directional drilling have lessened the burden on land departments, reduced truck traffic and its emissions, allowed drilling efficiencies and concentrated production facilities. Twenty-acre density drilling was approved at the end of 2005. Today, operators are drilling anywhere from five to 10 or more wells from a single pad. Microseismic has proven useful in understanding fracture patterns, well spacing and drainage patterns.

Joe Aucoin, facilities engineer for Anadarko Petroleum, calls the improved crude take-away capacity from the White Cliffs Pipeline “huge for us.”

Efficiencies are constantly being honed. Spud-to-spud times continue to fall (Anadarko has decreased drilling time by 40% since third-quarter 2007), while automated wellhead systems also reduce costs, notes Tony Scott, analyst with Bentek, in a report. In the first quarter, Anadarko set a company-record spud-to-spud cycle-time of 66 hours and Noble Energy has been achieving similar results since 2008.

The D-J rig count drop was 52% as of late May compared with the Rockies average of 65%. Vertical rig counts dropped by seven in the first week of February as operators ended their less efficient drilling programs, but rebounded to 12 in May. Rigs averaged two wells more per month in 2008 than they did in 2005, muting the significance of the rig count, notes Scott.

One of the biggest factors offsetting commodity-price lows is the pressure being exerted on vendors to lower prices. Some service costs have already fallen by 10% to 15%, and more significant declines are inevitable. More than one operator said it has asked for “’02 or ’03 prices, period.”

Weathering all prices

Trucks unloading crude at the White Cliffs terminal near Platteville, Colorado.

Noble Energy, based in Houston, entered Wattenberg through its acquisition of Patina Oil and Gas Corp., in May 2005, for $2.76 billion. It consolidated its position a year later with the acquisition of USX Exploration for $411 million.

The field is Noble Energy’s single largest onshore asset in North America; it operates some 5,250 wells there, has 900 more nonoperated wells and owns more than 330,000 net acres. It completed about 1,200 projects here in 2008.

About 55% of its stream is gas, and 45% liquids. As the largest producer of oil in Colorado, it yields about 20,000 barrels, and 185 million cubic feet of gas and 7,000 barrels of NGLs per day, gross. Its net operated daily production is about 145 million cubic feet of gas, and 15,000 barrels of oil and more than 5,000 barrels of NGLs.

Wattenberg provides a nice offset to Noble Energy’s international efforts, notes Ted Brown, senior vice president, North America northern region. “It’s a large inventory of low-risk projects with more than a 10-year-plus inventory, with high liquid content relative to other tight-gas plays in the Rockies.”

“Wattenberg lets us weather all kinds of price environments and gives us reinvestment choices,” says Larson.

Operators are obtaining anywhere from $1 to $1.50 uplift from Wattenberg’s NGLs per Mcf; during last year’s heady prices, it was a $1-to-$3 boost, says Ted Brown, Noble Energy Inc.’s senior vice president, North America northern region.

“This was a resource play long before anyone knew what a resource play was,” Brown adds, echoing the sentiments of other Wattenberg players. “We can stimulate the same formation three times and continue to increase recovery. It’s really a unique play in that you can utilize the same wellbore to recover oil and gas from the J-Sand, Codell and Niobrara, but you also can refrac the Codell and Niobrara, and then tri-frac—it’s a lot of completions in the same wellbore.”

In 2009, the company will drill about 400 wells—down from 500 in 2008—and refrac or tri-frac another 300-plus wells. It will not only drill in known areas, but will also look at expanding to the north and east on USX acreage to capture the oilier production. “It’s very attractive for us,” says Brown. The Wattenberg 2009 budget is about $400 million, down from last year’s $500 million. The company will run five to six rigs until the summer, when it will drop to three, and then ramp back up in the fall after crops are harvested.

Tri-fracing began in 2004, and timing is based on the pace of recovery. Primary recovery of the Codell and Niobrara is about a four-to-five-year process, then it’s time to refrac, and some five years after that, tri-frac the Codell.

The reserves keep adding up: Primary reserves alone, on a combo Codell/ Niobrara well, are some 40,000 barrels of oil equivalent. Refracing those formations adds 15,000 to 20,000 per; then ring up 10,000 to 15,000 BOE from a Codell tri-frac. Wells produce about 100,000 BOE over their life span.

Wattenberg lets the company weather all kinds of price environments and offers reinvestment choices, according to Dave Larson, Noble Energy’s vice president of investor relations.

Operators are still trying to understand the Niobrara, says Brown. “It’s not that tri-fracs won’t work, but it’s early in the process. Basically, when this was being drilled up in the early 1990s, the Codell and Niobrara had limited entry frac stimulations put on them, and everyone wrote off the Niobrara. Then we started looking at it in ’03 and ’04. We completed in the old wellbores up to the Niobrara, refraced it, and we’re targeting it quite a bit now.”

A typical well combining Codell and Niobrara production costs $600,000 to $650,000 to drill and complete, with the cost rising with the addition of more horizons. “These wells are 7,000 feet deep, and we can drill them in three days—it’s a pretty amazing road to efficiency,” says Brown.

Noble Energy had five of the top 10 footage rigs in the U.S. contracted in 2008. The top three footage rigs in the U.S. (according to the Land Rig Newsletter) all worked for Noble Energy in Wattenberg and drilled 2.1 million feet that year, 23% more than in 2007. The rig contractors are Ensign U.S. Drilling and Cade Drilling. Ensign is using automated drilling rigs (ADRs). Well-cycle times have fallen to three to four days.

Does exploratory potential remain in the basin? “There’s a lot of opportunity to apply new technology using 3-D seismic, and completion methods similar to horizontal wells drilled in the Barnett and Woodford shales,” says Brown.

“When you look at emerging opportunities in Wattenberg, there are just a number of zones out there or horizons that we know contain oil and gas—we drill through Pierre all the time, and there are deeper horizons like the Lyons—it’s just an awful lot of potential. There’s about a Tcf of resource potential out there, just on the emerging opportunities side, net to us.”

The potential involves Niobrara and Codell horizontals, multilaterals, and the deeper horizons.

Over the past five years, Noble Energy says it has more than doubled the number of its wells, as well as the IPs on some of those wells with refinements in stimulation design. Its focus on onsite best practices includes strict quality control and an engineer on each frac. Noble Energy employs different completion strategies depending on horizons, geographic location in the basin and estimated bottomhole pressures, which has improved recovery.

Overall finding and development costs are low compared to what industry has posted in the past several years, and operating expenses are also closely managed—the company figures its lease operating expense is about 50 cents per thousand cubic feet. “With low investment requirements, low operating costs and a large component of liquid value, you can understand why we’re remaining active out here,” says Brown.

Gas prices in the basin, where a significant amount of production stays close to home, is set at the CIG pipeline hub (at press time, $2.50 per Mcf). The natural gas liquids stream adds anywhere from 40% to 75% more to the price. Operators are obtaining anywhere from $2.50 to $1.50 uplift from the NGLs per Mcf, and in last year’s heady price days, as much as a $1-to-$3 boost. With nearly 50% of the stream being liquid, it greatly enhances the drilling well economics, notes Brown.

Selling points

Anadarko, which entered Wattenberg through its $16.4-billion purchase of Kerr-McGee Corp., posted 1,100 “green” recompletions last year and drilled some 379 wells. “Green complete means that we don’t vent any gas to the atmosphere following the frac and the well is put down line to produce, or shut-in until it can be put down line to produce,” says Eikenberg.

When asked Wattenberg’s selling points, Eikenberg echoes other operators. “It’s easy money. It’s not like drilling a wildcat here. It’s guaranteed.

“We’ve drilled dozens of wells that come on at around 1 million cubic feet per day initially, and then gradually decline until, a few years later when we can do a simple $250,000 frac job and have a brand new well,” he says. “We’re tri-fracing some zones, and where you get three or four or five pay zones in one well, you can keep fracing those zones, prolonging the life of the field and producing a lot of energy in the process.”

The company drilled 112 wells in Wattenberg with six rigs running in first-quarter 2009. It has since released two rigs.

Aadarko estimates a well costs about $700,000 to drill and complete. By using slickwater fracs, as opposed to the older-style gel fracs, it saves about $30,000 per frac.

The company is still experimenting with the best method to produce the Niobrara. Previously operators fraced all three benches of the Niobrara with one frac stage. Now, Anadarko targets some of the benches individually, setting frac plugs between stages and fracing each bench with 5,000 barrels of water and 200,000 pounds of sand.

The company began evaluating a shallower Sussex recompletion program in 2008. This program could add another layer of investment opportunities for the future.

About two-thirds of Anadarko’s wells are in cropland. One of its longest directionals stretched 4,000 feet under Milton Reservoir, southeast of LaSalle. It drills up to 14 wells off a single pad and consolidates the production facilities onsite to reduce its footprint.

Another cost-saver is its corrosion treating program. Since its inception in May 2005, the program has resulted in an estimated annual savings of more than $6 million. Currently, 2,800 wells are on a treatment schedule with more wells being added on a continuous basis.

Also active in the field is Petro-Canada Corp. Since acquiring its position in the D-J Basin from Prima Oil and Gas Corp. in 2004, Petro-Canada has grown its net acreage holdings from 30,000 at year-end 2004 to 168,000 at the close of 2008—a 460% hike.

Production increased last year by 27% over 2007 levels with 157 new wells. Its total well count, both operated and nonoperated, is more than 1,100. It has slowed operations in response to prices, but looks for a rebound. In late 2008, Petro-Canada bought 86,000 net acres in the northern part of the basin from Walsh Production Inc., and its 2009 program includes a drilling program on the Walsh lands.

The neighborhood

Dave Hill, Wattenberg team leader for EnCana, has spearheaded an initiative to promote the use of natural gas as transportation fuel, and has five dedicated natural gas Honda Civic GXs available for commuting and day-to-day business.

EnCana entered Wattenberg through one of its predecessor companies, PanCanadian, in May 2002. The company ranks No. 3 with 10% of the oil and gas production, and operates some 1,000 wells here, including the original discovery well from 1970. That well’s estimated ultimate recovery (EUR) from the J Sand, Codell and Niobrara is 75 million cubic feet equivalent.

In an interesting coincidence, notes Wattenberg team leader Dave Hill, the average daily production from the field is slightly more than an amount equal to a well’s life. EnCana’s wells currently produce 84 million cubic feet per day. The gas-to-oil breakout is about 63 million cubic feet and 3,500 barrels per day.

EnCana’s average speed to TD is now 4.2 days to 8,000 feet, either vertical or directional, aided by improved bit technology and drilling mud improvements.

The company has stepped back its plans for 2009 from 56 wells to about 27, but it has tripled the number of recompletions it anticipates from 40 to about 130. It plans about 240 refracs. “We look at Wattenberg as a resource-play model, with unconventional tight sand,” says Hill.

Standing on the site of the Wiggett 6-4-13 well being drilled by Patterson UTI Rig #34, with housing developments in full view, Hill discussed the increased density that came out of Colorado Rule 3-18A and now supports eight bottomhole locations on 20-acre spacing. The previous field rule allowed five surface locations on every 160 acres. Operators in the field assembled data to prove that, given the fracing program and drainage areas, the lease and section lines remained undrained.

Hay bales mitigate noise at the Wiggett #6-4-13 being drilled by Patterson Rig #34 for EnCana close to housing developments around the town of Erie

At the Wiggett, EnCana had five wells scheduled and anticipated a total drilling time of 24 days to complete them all, or about five days per well. “When this rig’s contract is up August 1, we’ll release it and just do recompletions until things pick up,” notes Hill. “With one rig, we’ll drill about 60 more wells this year, two cycles in the spring and fall.”

Hill estimates that completing to the J Sand, Codell and Niobrara costs about $940,000. Directional legs are about 1,650 feet.

EnCana’s use of a hybrid fracing fluid stems from its work in East Texas. “It’s something we took away from our work in the East Texas Cotton Valley/Bossier,” says Hill. “Using the combination, we’ve obtained a higher IP and EUR. Because we produce not only dry gas, we need the conductivity.”

The Wiggett site illustrates the need to address stakeholders’ concerns in the basin—municipalities, neighbors, state and federal regulations. “We originally planned to come down this access point,” says Hill, pointing to a different route than the one leading to the pad, “but the city said no, the neighbors said no. So we came over here to the county line road and completely changed access.” The process from title work to drilling can take 240 days.

Best management practices add significantly to costs. The town of Erie requested semi-decorative iron fencing around well locations at a cost of some $30,000 to $40,000 per installation. Placing hay bales to mitigate noise adds another $20,000; and pitless drilling, $55,000. But while well costs had been creeping up over the last four years, now they are declining 10% to 15%, Hill says.

Sound, light and dust pollution all must be addressed. “What’s required by regulations isn’t enough,” says Hill. “We take it upon ourselves to educate the community about operations in the field and what we’re doing, holding community meetings, and walk-abouts where we knock on doors and pass out information about ready-to-drill locations.”

The next reincarnation

How will Wattenberg reinvent itself next? Are there additional reservoirs capable of production?

“Of course,” answers Steve Sonnenberg, Colorado School of Mines professor of geology and holder of the Charles Boettcher chair in petroleum geology. He’s made a study of the D-J since 1978.

“There’s probably something else that to this stage we haven’t recognized. There may be other low-resistivity, low-reactivity reservoirs, or maybe the shale within some of these other formations will work too, and shale gas will become a big part of Wattenberg.

“The basin lies on top of a geothermal anomaly—a hot spot—where a zone of mineralization that took place during Tertiary time is associated with migration of ore-rich fluids. Where those two intersect, is right where Wattenberg is located. If there is a place where shale gas would work, it would be in the Wattenberg area.

“In Wattenberg we would have already seen more horizontal drilling but for the number of vertical wells that were already draining the areas. The technology is getting better and better, the frac stimulations are also improving, so reservoirs thought to be noncommercial 20 years ago are now commercial.

“If Wattenberg has nine lives, we’re only on about life No. 5.”