Rockies Niobrara

The horizontal Niobrara oil-shale play in the Rockies is like a company in the quiet period before an IPO. Amid cautions that it is early and debates about potential, there's an undercurrent of excitement. But how this play will price is not yet known.

Operators have drilled as many as 100 Niobrara horizontals, many of them not yet completed. Most have targeted the Denver- Julesburg Basin's Wattenberg Field and northeastern Colorado and southeastern Wyoming. At least 20 public companies and a slew of private E&Ps are drilling and/or hold acreage.

The internationals have arrived, too: China's CNOOC in January took a one-third interest in Chesapeake Energy Corp.'s 800,000 Niobrara prospective acres in Colorado and Wyoming for $1.3 billion; Marathon Oil Corp. announced a $270-million joint venture in early April with Japan's Marubeni Corp. for a 30% working interest in its Niobrara holdings; and Japan's Itochu Corp. acquired a stake in 22,000 net D-J Niobrara acres from Fidelity E&P Co. for $73 million, late in 2010. These capital infusions will help defray costs for U.S. partners as development proceeds.

a Cyclone Drilling Inc. rig hand maintains focus amid a late spring squall in the wind-swept southern Powder River Basin Niobrara play.

This widespread play, with multiple targets, is part of the immense Cretaceous section that traces the path of the Western Interior Seaway from Canada to Mexico. In the Denver-Julesburg Basin, operators are testing the shale in Colorado's heavily vertically drilled Wattenberg Field and in Wyoming's Silo Field, drilled horizontally in the 1990s but without the benefit of fracing technology. They are revisiting Colorado's Sand Wash, home to historic vertical Niobrara production, and they are drilling new horizontal Niobrara tests in multiple basins across the region: in the deep Powder River, Piceance, Laramie, North Park and more. And now, leasing has spread south of Denver to Douglas, Elbert, and El Paso counties.

"This aspect of the Rockies is unique," says Denver-based Ward Polzin, managing director and head of A&D for Tudor, Pickering, Holt & Co. "We have a lot of oil-bearing shales and sands and carbonates all within Cretaceous age in the Rockies, offering multiple shots on goal."

As the source rock, the Niobrara is the focal point, but as Polzin puts it, "It's like a day-long concert. The Niobrara is the headliner, but you want to hear all the bands." Operators are testing Frontier, Greenhorn, Sussex, Mowry, Parkman, Mancos, Turner and more.

In 2009 and 2010, debate centered on what would make an economic well. Was it necessary to have natural fractures, or would matrix contributions suffice?

"For 50 years, Cretaceous targets like the Frontier in Wyoming, and Niobrara-sourced targets like the Shannon, have been drilled and produced on very specific fields that have structure," says Polzin. "Now, operators are trying to make the matrix play work away from structures."

This year, with oil topping $100 per barrel and operators versed in horizontal fracture stimulation, it's all about cracking the shale's drilling and completion code.

"The secret code is the frac," says Polzin.

Operators are trying to make the Niobrara matrix play work away from structures, notes Ward Polzin, managing director and head of A&D for Tudor, Pickering, Holt & Co. “The secret code is the frac.”

Taking the technology lead is EOG Resources Inc., which drilled the Jake #2-01H discovery in Weld County's Hereford Ranch Field to kick off the play in 2009. In a late April earnings call, Mark Papa, chairman and chief executive, said EOG is No. 1 in horizontal oil-play technology and is experimenting with new completion techniques for the Niobrara's matrix and fractured plays. While admitting the shale is "complicated," he said EOG's "really positive results" had shifted his outlook from cautious to optimistic.

"We've made great strides in improving our understanding of the play on our 80,000-net-acre Hereford Ranch Field, where production is 4,000 barrels of oil per day net," he said. "During the remainder of the year, we'll test the other portions of our 220,000 total net acres."

EOG has a three-rig program in the D-J to drill 40 more horizontals this year. Recent wells such as the Critter Creek #13-17H and Elsie #7-34H tested at 731 and 820 barrels of oil per day, respectively.

The company gauges well costs in the fractured play at $3.6 million, and in the matrix, at $6 million. "While the matrix play wells cost more, they have higher resource recovery, so you're able to drill more wells per acre, per section," he said. "But the economics on both play types, we think, are going to be very strong." He declined to offer per-well reserve estimates.

Papa said EOG holds 138,000 net acres in the Powder River Basin prospective for multiple pay horizons. To date, it's drilled eight successful horizontals in the Turner sandstone there and may test Niobrara later this year.

As of late April, 27 Niobrara rigs were at work in the D-J/Powder River Basin, according to Hart Energy. Some 172 permits had been issued for horizontals during the first quarter versus 333 for all of 2010, largely targeting Weld County. Thirty horizontals had been spudded in Colorado. In Wyoming, nearly 400 Niobrara permits had been issued in the past six months.

As for seismic, in Colorado some 355 square miles of 3-D seismic had been filed for in 2010-2011, with much of it scheduled for this year. Additionally, there are 13 2-D projects totaling some 157 miles. In Wyoming, five permits have been issued each for 2-D (285 miles) and 3-D work (365 square miles) to date in 2011.

This is the year of seismic, science, and plenty more wells.

rig hands apply pipe dope to the threads of a new bit being added to a horizontal drilling motor assembly.

D-J Basin

Along with Anadarko Petroleum Corp., Noble Energy Inc. is one of the largest players in Wattenberg, with the benefit of data from its many verticals in the field. The company's results show strong matrix contributions from the Niobrara's high-porosity chalks, with success not limited to natural fracture systems. The company drilled 27 Niobrara horizontals in 2010, and plans 70 this year.

At a recent presentation in Denver, Noble Energy vice president of Wattenberg operations Dan Kelly alluded to the irony of finding the industry's hot new oil-shale play in Wattenberg.

"Over the years, Wattenberg drillers just kept drilling verticals, putting money in the bank by keeping wells as inexpensive as possible, while still delivering a good product," he said.

"The last thing you wanted to do was throw science at it. You might learn something," he joked.

"But what we've found today, with horizontal development, is that you can't throw enough science at this. We believe in 3-D seismic wholeheartedly, we think it's the future of how we're going to steer the wells, decipher which direction to drill in, and potentially even how we'd like to complete these wells." It is participating in a 3-D shoot covering 1,000 square miles in its "extension" area in northeast Colorado and southeast Wyoming.

Last year it acquired Suncor assets for $494 million and now holds more than 830,000 net acres in the D-J. It produces more than 55,000 barrels of oil equivalent (BOE) per day from Wattenberg, 50% of that liquids. Noble Energy has earmarked $800 million in 2011 for the combined Wattenberg Field and central D-J program, and will drill 485 verticals targeting Codell/Niobrara in addition to horizontals.

The company has completed eight horizontals in the Wattenberg core and 18 in the extension area. The center of Wattenberg has a high gas-to-oil ratio, and the core horizontals are averaging 640 BOE per day on a 30-day initial potential (IP), with 55% liquids. Just northeast of Wattenberg, horizontals are yielding some 430 BOE per day with 70% liquids. The company pegs estimated ultimate recovery (EUR) for the horizontals at 310,000 BOE. The average vertical posts just 40,000.

Rick McCullough, chairman and chief executive of PDC Energy, looks for internal rates of return of 80% from the company’s Niobrara slice.

"What makes Wattenberg unique is its thermal maturity," says Polzin. "You have almost the perfect mix of oil and gas. That's why it works both vertically and horizontally. They've got porosity, good permeability, and energy from the gas. It's easier to get a better well in Wattenberg."

Noble Energy estimates original oil in place for horizontals in Wattenberg, where, combined with vertical wells they can lead to 8% to 10% recovery per section, at 20- to 30 million BOE per section. Well costs average $3.5 million.

The company has data from nearly 5,000 vertical wells it's drilled in Wattenberg. A challenge is how to place horizontals among the verticals, but it has determined Niobrara verticals drain less than 10 acres; current spacing is at 32 and 20 acres.

In January 2010, the company spudded the Gemini well to test how horizontals could offset the verticals and increase drainage. It was drilled on two 20-acre sections, down the center of two five-spot patterns. Drilled and fraced in 16 stages, it has an EUR of more than 700,000 BOE. "It was a game-changer in Wattenberg and for the Niobrara," Kelly said. It has produced 200,000 BOE to date.

Earlier this year, Noble Energy drilled the Hanscome, another horizontal among verticals, again with good results: a 24-hour IP of 1,250 BOE per day and a 30-day average of 900 BOE per day on a restricted rate.

Noble Energy is targeting the B bench of the Niobrara—the chalk—but it is also looking at the Codell and the C chalk lower Niobrara member.

In Wattenberg, the company puts its unrisked resources at more than 600 million BOE, with 2,000-plus horizontal locations. It looks for upside from the horizontal Codell; from multilaterals within the Niobrara; and from the Greenhorn shale/limestone.

Outside Wattenberg, Noble Energy plans to run one rig (four horizontal rigs are currently in Wattenberg, one will move between the two areas) through 2011 as it continues to test fractures, matrix porosity, lateral geometry and completion designs.

The company puts its net unrisked horizontal potential at more than 1 billion BOE.

"We're awfully excited about what we're sitting on," said Kelly.

PDC Energy, Denver, also is excited about the Niobrara. It drilled its first horizontal Niobrara well in its Krieger prospect area this past November. The Rickards 41-10H IP'd at 625 BOE per day and has posted a 30-day average of 310 barrels equivalent. It targeted the B bench with a 4,000-foot lateral and a 16-stage frac; the well was drilled and completed in 14 days at a cost of about $4 million and began gas sales in early January, without artificial lift.

"Our best assessment is that once the pump is on, total recoveries from the Rickards should be in the 270,000 BOE range," says Rick McCullough, chairman and chief executive officer. He looks for internal rates of return of 80%.

In late 2010 and early 2011, the company drilled its first two horizontal wells in the northeast fringe of Wattenberg. Initial results were encouraging, with the two wells averaging combined production rates of 1,004 BOE/d.

PDC plans to drill 14 horizontals in 2011 in the Niobrara: four to five in the Krieger area, and nine to 10 in the core. All are in Weld County. The company estimates it has at least 125 horizontal locations in the play, with 100 in the core area and 25 in the Krieger prospect.

The company will scale back vertical drilling this year. In 2010, it drilled about 170 verticals to the Codell/Niobrara and did about 30 refracs. This year it will have two rigs running, with one dedicated to the horizontal program, and will drill 90 verticals, 14 horizontals, and do 140 refracs.

PDC has held most of its Niobrara acreage for eight to 10 years. "We're very fortunate," says McCullough.

No. 1 rate of return

At press time, Carrizo Oil & Gas Inc., Houston, had agreed to sell its noncore Barnett properties to KKR Natural Resources for $104 million, giving it additional liquidity to develop its Eagle Ford and Niobrara positions.

Carrizo Oil & Gas Inc. vice president and chief operating officer Brad Fisher notes the company’s acreage position is “pretty well blanketed in” between Colorado’s Wattenberg and Wyoming’s Silo fields.

Out of a total 2011 capex budget of $309 million, it has earmarked $35 million for the Niobrara, where it estimates it has 97 horizontal locations on 320-acre spacing.

Carrizo began acquiring Niobrara leases a little over a year ago and now holds 62,000 net acres northeast of Wattenberg, in Weld County. "We're pretty well blanketed in between Wattenberg and Silo fields," says Brad Fisher, vice president and chief operating officer.

"We mapped into our position using data from a lot of old extensional wells from Wattenberg that chased the deeper D and J sands, and using structural trends interpreted from our 2-D seismic. We used that as the resistivity model for what we think are the mature, productive fairways. Our acres were purpose-bought, and that sets us apart from companies with legacy acreage."

Carrizo has drilled three horizontals. The State #1-16H IP'd at 690 BOE per day; the Bob White #1 tested at 725 per day, and the recently completed State #61 tested at 681 per day. The company is using 5,000-foot laterals with 15 frac stages, with the lateral based in the B bench. The well cost averages $3.6 million.

The company is in an area with a high oil component to its production. "Even though the Niobrara in Wattenberg looks excellent, with high porosity and resistivity, it is much gassier than where we're drilling," says Fisher. "Our GORs (gas-to-oil ratios) are 600, and during production might move to 1,200. The Gemini was a huge well, but the GOR is 11,000.

"When you convert that, just 31% of the production is oil. Ours is 90% oil. That's an enormous difference if the cost to drill is the same."

On its first well, Carrizo, drilling off of nearby 2-D control, encountered unexpected faults, so it ran a seismic line down the second well, which showed a 120-foot fault. It was able to stay in zone 90% of the time. It's now participating in a 150-square-mile portion of a large 3-D survey that crosses its acreage, some of which has been processed.

"The entirety of the shoot, which goes up into Wyoming, was well over 300 square miles, but I've heard it has been upsized to nearly 1,000," says Fisher. "I have never seen a better place to shoot seismic—there's nothing to get in your way."

Carrizo plans to run one rig through 2011, drilling 10 to 12 gross wells. The first, to be drilled off of 3-D, will test the southern end of its acreage in Morgan County, Colorado.

Fisher and Richard Hunter, vice president of investor relations, agree that it's all about completions. "How do we effectively fracture stimulate the interval and determine the optimal well spacing? We have a lot of work to do there," says Fisher. "We have microseismic data on our wells indicating the fracs are not reaching out very far. There may be a good opportunity for 160-acre spacing."

Microseismic helps to determine how effectively the Niobrara is being drained from top to bottom, in the three potentially productive intervals. Carrizo drilled a "listening" well about 400 feet off the horizontal path of the State #61. "We should have pressure communication between the two, so we'll reenter to do some pressure monitoring."

Carrizo's typical completion to date has used swell packers, but it will test a cement liner and a plug-and-perf completion on an upcoming horizontal. "We want to see if with plug and perf we can impact more rock. That's the biggest hurdle, to effectively drain the matrix."

a new bit heads south at Chesapeake Energy’s Sundquist Flats Unit #1H.

How do the economics stack up against Eagle Ford wells? "At an EUR of 300,000 it is the No. 1 rate-of-return deal we have in our company, although we don't have the data we have from other plays to solidify the type curve," says Fisher.

At a $60-per-barrel Nymex price, Carrizo estimates the IRR for its Niobrara wells at 41%; at $75 Nymex, 84%; and at $90, 146%, with F&D costs at $15 per barrel. Reserves are 300,000 BOE gross, 240,000 net.

Marathon Oil Corp., Houston, considers the Niobrara shale an emerging growth area. It began leasing in the D-J Basin in 2010 and has acquired 180,000 acres in Wyoming's Goshen and Laramie counties, and Colorado's Weld and Larimer counties.

Dave Stone, director of North American exploration business strategy, notes the company is expanding in four major unconventional oil-rich resource plays in the U.S.: the Anadarko Woodford, Eagle Ford, Bakken and Niobrara. The company's position and experience in the Bakken, where it has an active drilling program on 391,000 acres, was one of the reasons it became active in the Niobrara.

Marathon is the largest oil producer in Wyoming, and Niobrara development aligns well with its Rockies oil business. "This is an operational base of opportunity for us," says Stone.

The company is reprocessing an extensive 2-D seismic database covering the D-J Basin. And, it is acquiring additional data. "As we prepare to drill, we are acquiring proprietary 2-D seismic across our drillsites; in addition, we're participating in several 3-D seismic surveys with industry," says Roger Pinkerton, director of North American onshore exploration.

An eight-to-12-well horizontal program is planned for 2011, with one rig in May beginning to drill four to six wells in Weld and Larimer counties; the program will then move to Goshen County.

Marathon expects to benefit from its Bakken drilling and completion know-how. "The Middle Bakken play ranges across several geologic reservoirs, from siltstone to dolomite to a sandstone facies, with different technical attributes, so we bring that geological and technical expertise to the Niobrara play," says Stone.

Partnering with Marubeni assists the company in de-risking its position in the emerging play. Marathon estimates it has 600 potential Niobrara locations on its acreage, at 160-acre spacing, with resource potential of 125- to 175 million BOE.

Northern D-J

In the northern D-J, companies have focused drilling in and around Goshen County, some 50 miles north of Silo Field. Among those holding acreage and with plans to drill this year is Perth, Australia-based Samson Oil & Gas Ltd. It established a position in the Niobrara early, acquiring with Mountain Energy of Denver a half interest in 100,000 acres in Goshen County in 2006. At year-end 2010 it sold some 24,166 gross and net acres of its position for $73.8 million to Chesapeake Energy. Samson is using the capital to expand its Bakken oil-shale position and develop the Niobrara on its retained 16,379 net acres in the Hawk Springs project.

Dave Stone, director of North American exploration business strategy for Marathon Oil Corp., calls the Niobrara an operational base of opportunity.

Also late in 2010, Samson acquired a 63-square-mile North Platte 3-D seismic survey on Hawk Springs. The survey is being interpreted and processed to evaluate both conventional, J Sand, and unconventional Niobrara targets, according to managing director Terry Barr.

In late January, Samson formed a JV with Halliburton for $9.5 million to develop some 11,277 of its acres in Goshen County. Halliburton has committed to drill and complete up to two test wells in the play and will earn a 25% working interest in acreage subject to the JV, carrying Samson on the first two wells, with the first expected to spud in June. The JV secures access to technology, equipment and personnel.

Samson's holdings are north of Silo Field by about 40 miles. Barr doesn't concur with the notion that the core Niobrara play is in Wattenberg Field and its environs. "It's quite the opposite," he says. "It is the most mature part of the Niobrara, so in essence, it's not the core.

"The key issue is maturity and the thickness of the Niobrara, both of which are associated with the syncline, deeper depth of burial and greater thickness compared to the flanks of the basin."

The closest wells to its current position were drilled by Chesapeake Energy on the acreage sold to it by Samson—Chesapeake has drilled about six wells there and fraced two.

At present, Samson expects to spend about $5 million on its Niobrara program in 2011.

Also active in the northern D-J is Denver-basedFidelity E&P Co., a unit of MDU Resources Group, Bismarck, North Dakota. With experience from some 40 horizontals in the Bakken shale, Fidelity this past year assembled Niobrara positions in Laramie and Goshen counties. One block is southeast of Silo Field, and the other two are north of Silo. Late in 2010 it sold a 25% interest in its 88,000 acres to Itochu Corp. of Japan.

"Our exploration group had done some geological assessment and review back in 2008 and 2009, looking for areas to use our Bakken expertise," says Steve Bietz, president and chief executive officer of WBI Holdings Inc., the holding company for Fidelity. The JV came about as Fidelity looked to derisk its Niobrara investment. Itochu's E&P subsidiary in Houston was looking for a nonoperated position in an oil play. The two companies also formed an area of mutual interest, so as Fidelity adds to its acreage, both can participate.

Roger Pinkerton, director of North American onshore exploration, notes Marathon is participating in industry seismic shoots and acquiring proprietary seismic across its drill sites.

Fidelity shot 3-D seismic over a "good chunk" of its acreage in 2010, and is conducting more seismic this year. The company has budgeted $14 million for two wells, 3-D and other technical work. "We're fortunate to have good lease terms—five-year initial terms with five-year extensions over a good portion of it—so we don't have to rush to do drilling, we can watch the data around us, interpret our own, and manage the risk going forward," says Bietz. "If our results are encouraging this year, we plan a 12-well drilling program for 2012."

Bietz expects development of the Niobrara will take much the same course as the Bakken. "We've been in the Bakken for four years now, and initially, results were mixed. There were sweet spots, and others that were not as productive. As time went on, different companies tried different completion methods and drilling techniques, and the play moved forward.

"In the Bakken, completions were taken from single to seven stages to 18 to 20 stages; now some are 30- to 40-stage completions. That's opened up a lot of other acreage. The same is likely to happen in the Niobrara."

Southern Powder River

Chesapeake Energy Corp., Oklahoma City, began accumulating acreage in the southern Powder River Basin Niobrara play, largely in Converse County, Wyoming, as far back as 2007. About half of its 800,000-net-acre position is in Converse County, with the other half distributed south from Cheyenne to Wattenberg.

"We saw the Niobrara as an area of opportunity to help rebalance our portfolio with potential for long-term oil reserves, low-cost acreage and to use technology from our other shale plays to develop this into a sizable asset," says John Suter, vice president of operations, western division.

ohn Suter, Chesapeake Energy vice president of operations, western division, says the company’s JV with CNOOC joins capital with technical resources to develop the Niobrara.

"We also like the potential for multiple targets, which adds more excitement to the package. The Niobrara and Frontier are obvious choices, but we're seeing others—Parkman and Sussex, for example—that are a little bit shallower in the area but still potential targets."

Chesapeake ratcheted up industry interest in the Niobrara when it announced the JV with CNOOC. "There's a lot of capital in the foreign markets," says Suter, "and here in the U.S., we are prospect rich with a number of unconventional-type opportunities. With leasing deadlines, the capital requirements are challenging, so the JVs have been a win-win, bringing capital and technical resources together to develop some of these very large resource plays."

The Powder River Basin Niobrara play is at an earlier stage of development than the traditional D-J activity around Wattenberg Field. "We'll establish core areas for the best returns and then delineate the play boundaries to hold the acreage for future development."

Chesapeake in late April had five rigs drilling throughout its acreage and planned to escalate that number to 15 by year-end, and to 20 by 2012. It will concentrate in the Powder River, where its entry cost was low and it has a large contiguous block of acreage for development.

Days to drill and complete average 50, decreased from 70 not long ago, depending on depth. Once 15 rigs are put to work, Chesapeake expects to drill and complete two wells per rig on average every three months. Costs and rig time continue to decrease.

Suter says IPs have averaged 800 to 900 BOE per day. EURs are 500,000 BOE, significantly higher than Noble's estimates for the Wattenberg core. The Powder River Basin is generally deeper and exhibits higher reservoir pressure than the D-J. "As we get our process into full swing, we should be able to eliminate some of the technical data-gathering costs and generate nice returns on investment," says Suter.

So far, Chesapeake has about 10 wells down to the Niobrara or Frontier formations in the Powder River Basin, and has drilled another eight on its D-J acreage. The latter are still testing or waiting to be completed and were just drilled in recent months. Most of its Powder River Basin wells came on in 2010 or early this year, but several remain to be completed.

In both the D-J and the Powder River focus areas, Suter says contributions from both natural fracturing and matrix porosity are important. "We're trying to develop fracturing technology where we can still get favorable returns from primarily matrix deliverability. The fracture component does help out with better initial rates, but we don't believe it's a make or break for the play.

"We believe the shale by itself is still productive, as is the case with the Frontier formation also. We don't have to have highly fractured areas, but it's great when you do."

Samson Oil & Gas Ltd. managing director Terry Barr notes the company’s Niobrara JV with Halliburton secures access to technology, equipment and personnel.

Laterals are ranging anywhere from 4,000 to 6,000 feet, with the latter being more typical in Wyoming, where federal units allow longer horizontals. The company is averaging about 12 fracture stages per well. Drilling and completion costs in the Powder River are higher than in the D-J, because of the longer laterals, greater depths, and other factors. The Converse County wells are averaging $7- to $8 million, but as Chesapeake establishes a factory process, "we'll put a dent in costs," says Suter.

The decline rates typically settle at about 200 to 300 BOE per day. The average IP rate from Frontier wells is 1,060 BOE per day, and from the Niobrara wells, 540 BOE per day.

"Just like in every shale and resource play, you have to do a lot of core and log analysis," says Suter. "It's critical to understand the rock mechanics for efficient drilling and optimization of hydraulic fracturing.

"We have our own lab with state-of-the-art equipment to provide these measurements and analyses. It helps us to define our most permeable portion of rock to target. And, with naturally fractured reservoirs, sometimes defining lateral orientation is important to intersect the maximum number of fractures.

"Underbalanced or managed pressure drilling can be key to controlling fluid loss in these reservoirs, both in reservoir performance and in helping to control the well cost. We have to deal with bitterly cold temperatures in winter, so we must manage our completions so fluids don't freeze. Time optimization becomes a critical issue. We also have complexities with deeper wells in the Powder, where we have to consider artificial lift technologies in these high-volume fluid plays."

Chesapeake is using pumping units at present but as gas pipeline infrastructure is built Suter thinks gas lift could be effective. "We ultimately hope to have some sort of pump we can put in the lateral section of the wellbore, such as hydraulic pumps, that will be a big benefit," he says.

Typical GORs throughout its area of the play are about 1,000 to 2,000. Porosities in the Niobrara shale range from 4% to 12%.

At press time, Chesapeake was drilling a Niobrara wildcat, Sundquist Flats Unit #1H, to a total vertical depth of 11,905 feet with a 6,100-foot lateral. In Converse County, it is about four miles from the Northwest Fetter Unit #1H. The company has used a combination of swell packers and plug-and-perf designs for its completions, which have ranged from eight to 15 multistage fracs.

Laramie Basin

Testing Niobrara in Wyoming's Laramie Basin is Denver-based Laramie Energy II LLC. The private E&P, which has focused in the past on Rockies unconventional gas, has been evaluating the Niobrara's oil potential since 2007.

The Niobrara is not a uniform or traditional resource play, says Laramie Energy II LLC chief executive officer Bob Boswell. The company will drill Niobrara horizontals this year in the Laramie Basin.

"It's not a uniform or traditional resource play," says chief executive officer Bob Boswell. "It varies from basin to basin and within basins. Some have the right thermogenic properties and history. Areas where you have productive fields are good indicators that there are other areas reasonably close by that may be productive."

Laramie has accumulated about 80,000 net acres in the Laramie Basin and about 10,000 net in North Park, Colorado. Laramie's strategy is to first evaluate burial history, petrophysical properties and temperatures, so it is drilling vertical wells before going horizontal.

The company plans to redrill two verticals as horizontals later in 2011. The first, in North Park, was drilled in 2008 on the theory that it was necessary to be near large fractures/faults to get commercial production. The well flared oil and gas but the openhole completion failed.

"We took that information and went through a series of interpretations and geochemical work and determined we had the opportunity to go horizontal," says Boswell. That well, the Fuqua, will be redrilled this summer.

The second well, the Dunmire, drilled in late 2009 in Albany County, Wyoming, was drilled on the theory that microfractures and containment were needed for commercial production. After analyzing the vertical effort, Laramie concluded there were microfractures present and will now take it horizontal.

A third well, the Booth, a true horizontal south of the Dunmire, will be a hybrid. It has lineament surface expressions indicating that it is somewhat fractured, but not by large tectonic-type faults, says Boswell. It offsets a well that had Niobrara shows, but it will also look at the Mowry formation.

"We have three different approaches, and we'll see what setting works best," says Bos­well. Cores will help determine how important permeability is, and how important it is to have interconnected porosity. "We know permeability can change rather rapidly from area to area. So one well that doesn't produce doesn't condemn a whole area."

The Niobrara oil reentries will cost about $3.5 million through completion and multistage fracturing. The new horizontal will cost $4.5- to $5 million. Boswell figures an EUR of some 250,000 barrels will make a commercial well.

Steve Bietz, president and chief executive of WBI Holdings Inc., the holding company for Fidelity E&P, expects Niobrara development to follow much the same course as the Bakken.

Early stage

Activity through the remainder of 2011 will go a long way toward further defining the extent of the Niobrara's potential.

At press time, new entrants to the play were awaiting results. Bakken veteran Continental Resources Inc., Oklahoma City, was completing its first Niobrara horizontal, the Newton #1-4H, and the first spaced on 1,280 acres, in Weld County. It had 8,050 feet of lateral in the zone. The company holds 71,712 net Niobrara acres in Colorado and Wyoming. Whiting Petroleum Corp., Denver, had two Niobrara horizontals recovering frac load, part of a seven-well exploratory program. Rex Energy Corp., with 45,000 net acres in the D-J, had three horizontals drilled and fractured but had not yet released results.

More results are imminent. Tudor, Pickering's Polzin stresses both positives and weaknesses as he assesses the play. "The big picture is, it's early stage, but there have been lots of good wells. It's important not to get caught up in bad wells—we're where the Eagle Ford was three years ago. This is just beginning, and there are a lot of zones to test."