T?he first impression a newcomer has of North Dakota is the immensity of its white-blue sky. This is vast and open country, a land of bountiful wheat fields, wondrous badlands and unbroken vistas.


And, beneath the wide plains of the Roughrider State lies a resource that displays the same grand scale. The Williston is the largest sedimentary basin onshore the U.S., and it contains the largest undeveloped oil play in the nation. The Bakken resource resides in a complex shale reservoir composed of interbedded sands, silts, dolomites and limestones.


The extent of North Dakota’s Bakken play is phenomenal—it stretches many miles across rolling prairie, from Columbus to Killdeer, and from Williston out past Stanley and down south of New Town. Indeed, the U.S. Geological Survey recently estimated that the Bakken contains mean undiscovered volumes of 3.65 billion barrels of oil, 1.85 trillion cubic feet of gas and 148 million barrels of gas liquids. These are technically recoverable volumes, spread across a resource that covers some 25,000 square miles, including portions of eastern Montana. In addition, southeastern Saskatchewan holds another 1.3 billion barrels of technically recoverable Bakken oil.


These days, big triple rigs punctuate the broad Dakota skies. The play is booming: more than 60 rigs are at work in North Dakota’s Bakken play, and wells are being drilled and fractured, tanks are being set, gas plants are under construction and pipelines are being laid. Yet, the wide spacing of the big horizontal wells—they stretch up to 9,000 feet laterally at vertical depths of some 10,000 feet—means that the activity is still dwarfed by the rolling grasslands.


North Dakota had its first love affair with the Upper Devonian/Lower Mississippian Bakken shale in the early 1950s, when production on the crest of the great Nesson Anticline was discovered. This long, narrow structural feature collected Bakken-generated oil in several formations. Vertical wells at McKenzie County’s Antelope Field produced strongly from fractured Bakken shale and underlying Sanish sand, but across most of the area the Bakken served mainly as a stand-in when other objectives faltered.


The next flirtation teased in the late 1980s when horizontal-drilling technology was tried in the Bakken shale. Drilling centered on the Billings Anticline, another regional structural feature that trends through Billings, Golden Valley and McKenzie counties. Some 30 million barrels of oil were produced from horizontal wells in the upper, shaley member of the Bakken. The thin, organic-rich source rock appeared to be a good target for horizontal wellbores, as the laterals could intersect natural fractures that provided conduits for oil.


These early horizontal Bakken wells didn’t access enough crude, however, and the play withered when oil prices fell below $20 per barrel. The natural fracture systems that supplied the Bakken’s permeability were just not widespread enough or predictable enough to support a commercial play. Peak Bakken production rates reached 10,000 barrels per day in the early 1990s, and declined steadily thereafter.


The current blossoming of the Bakken began to unfurl in 2000. Near the southwestern edge of the shale’s extent, in Richland County, Montana, operators began to drill horizontal wells. The core movers in the play were private firms, so the play stayed fairly quiet.
Lyco Energy Corp., based in Dallas, launched the Montana play. The company discovered a tremendous stratigraphic trap in the Middle Bakken dolomite, a four- to 15-foot interval sandwiched between upper and lower shales. Initially, Lyco drilled vertical wells, but in 2000 it spudded its first horizontal.


That well, #36-2H Burning Tree State, was encouraging. Other private operators moved quickly to capitalize on the discovery: Headington Oil Co. and Petro-Hunt, both based in Dallas, and Slawson Exploration Co. of Wichita, Kansas, built positions. Public companies such as Denver-based Whiting Petroleum Corp. and St. Mary Land & Exploration, and Houston-based Burlington Resources and EOG Resources Inc. joined in.


To date, Elm Coulee has produced more than 69 million barrels of oil from more than 580 horizontal Bakken wells. A typical well can ultimately recover 450,000 barrels of oil equivalent (BOE), and the 500-square-mile field will likely yield more than 300 million barrels of oil. The U.S. Energy Information Administration ranks Elm Coulee as the fifteenth largest oil field in the onshore Lower 48.

Building out
Enid, Oklahoma-based operator Continental Resources Inc. moved into the Elm Coulee play in its infancy. The company was looking for oil, and it liked the opportunities it saw in the Rocky Mountain region. “We were interested in the Williston, Big Horn and Powder River basins,” says Harold Hamm, chairman and chief executive. “We think oil has more intrinsic value than natural gas, and we wanted to find large fields.”


Continental was already a Williston producer when Lyco’s Bakken play emerged. Continental worked the Red River in North Dakota’s Slope and Bowman counties and South Dakota’s Harding County. It had honed its horizontal-drilling expertise in Cedar Hill Field, which it developed entirely with horizontal wells beginning in 1995.


The company favored cutting-edge technology, and it hunted places where it could use horizontal drilling to its advantage. It came across the Bakken play in Montana as the earliest horizontals were being drilled.


“In 2001, when we saw the play was likely to work, we immediately began to lease,” says Hamm. Land was available for $35 to $50 per acre, and it wound up with 125,000 acres in the burgeoning field. It drilled its first well in the field in 2003, and since then has drilled more than 140 producers.


Today, Continental makes 8,200 net BOE per day from Bakken wells, and about 7,000 comes from Elm Coulee. It currently runs three rigs in the field, working on infill locations. The first well in a 1,280-acre spacing unit at Elm Coulee recovers about 450,000 barrels estimated ultimate recovery (EUR), and the second about the same volume.


Last year, Continental tested 320-acre spacing, and results were robust. The infill wells have recoveries approaching 400,000 BOE, substantially higher than anticipated. “We’re now drilling our Elm Coulee acreage down to 320-acre spacing, and we have about 60 locations left to go,” says Hamm.


Elm Coulee’s Bakken also offers a tremendous EOR target. This fall, Continental plans to install both a huff-and-puff CO2 pilot and a waterflood pilot. It will bring in CO2 for the pilot by rail.


But the future of the Bakken lies in North Dakota, believes Hamm.

Neighboring state
Emboldened by its success in Montana, Continental moved into North Dakota in 2003. It focused its efforts along the Nesson Anticline, where the Bakken is thick, has a history of vertical production, and is naturally fractured. Initially, it put 100,000 acres together and started horizontal drilling.


This incarnation of horizontal work in North Dakota wasn’t notably successful. At Elm Coulee in Montana, operators drilled dual-leg laterals, left them openhole and fractured each leg separately. “We tried that same thing in North Dakota and it didn’t work,” says Jeff Hume, senior vice president, operations.


The problem was that North Dakota’s Bakken had a higher frac gradient than Montana’s Bakken. Fracs broke up into the Lodgepole in North Dakota, and the Bakken wasn’t being as effectively stimulated. Continental shifted to single 9,000-foot laterals, and started to run uncemented casing and swell packers. “We’ve climbed the learning curve. We stage frac with the plug-perf method, with 10 separate stages per lateral, and have plans to increase the number of stages on future wells.”


Immediately, results improved 100%. At the same time, the company continued to lease all along the trend of the Nesson Anticline, accumulating more than 350,000 net acres.


“When we went public in the spring of 2007, the Bakken was out of favor,” says Hamm. “But we started making some consistently good wells, and that turned perceptions around.”


In 2007, the company drilled 27 Bakken wells in North Dakota that averaged 335,000 barrels EUR each. That included the good, bad and ugly, and they tested acreage all along its 140-mile acreage position. This year, results have been even better: consistently, across its entire area, initial production rates suggest EURs could average more than 400,000 barrels per well.

Portentous addition
As robust as the Bakken is proving to be, Continental added to that bounty with its #1-29H Bice, drilled into the Three Forks-Sanish in Dunn County. The Bice flowed 700 barrels of oil per day for its first week of production. Moreover, Continental recently announced results of another major Three Forks-Sanish success. Its #1-35H Mathistad, in McKenzie County, came on line at an average rate of 1,198 BOE per day. That well is 23 miles north-northwest of the Bice.


Interest in the Three Forks-Sanish is extremely high across the basin, as the implications for future production and reserve additions are considerable.


“When we took this lease position, we looked at a lot of core data. And we could see staining as much as 50 feet into the Three Forks,” says Hamm. The Lodgepole is such a great seal that oil generated in the Bakken has been forced into the top of the Three Forks-Sanish, a Devonian formation that lies just below the lower Bakken shale.


Indeed, the entire interval from some 150 feet into the Three Forks through the Bakken and into the base of the Lodgepole is thought by some workers to be a unified source system, and any porous zone within that interval will be charged with oil. What’s so attractive about the Three Forks-Sanish is that it can have higher porosities and permeabilities that the Middle Bakken. That can add considerable matrix storage.


The Bice and Mathistad discoveries herald this huge additional potential: “We think that the Three Forks-Sanish could be a separate accumulation, in addition to the Bakken. It could double the Bakken resource.”


Support for this concept also comes from the best well in the Bakken play. In the fall of 2006, Petro-Hunt LLC completed #2D-3-1H USA in Charlson Field, McKenzie County, for 729 barrels of oil and 785,000 cubic feet of gas per day. It featured a single, openhole lateral that extended 3,200 feet into the Three Forks. According to state records, in the 18 months from October 2006 to March 2008, the well made 437,509 barrels of oil and 538.2 million cubic feet of gas. It still makes some 700 barrels a day. “It’s a horse of a well,” says Hamm.


This year, Continental will spend $245 million and drill 41 net wells in the Bakken, including additional tests in the Three Forks-Sanish. The company has 15 rigs working in the Bakken, a dozen of which are in North Dakota. That includes a joint venture it has with ConocoPhillips that it entered in 2006.


“We were all taught that shales were impermeable source rocks. But breakthroughs in precision horizontal drilling and multi-stage, high-pressure fracs at high rates have made all the difference,” says Hamm. “All that technology is responsible for allowing industry to harvest the shales, and it’s been done by a small group of independents.”


Certainly, the performance of the stocks of the 15 independents that focus on resource plays in multiple basins has increased exponentially. “The market is paying for the tremendous opportunities that this new technology has opened up. It’s a great land rush—companies are nailing down positions in plays all over the country. And the Bakken is unique among the major resource plays because it produces oil.”

Whopping discovery
The hottest area in North Dakota’s horizontal Bakken play is in the vicinity of EOG Resources Inc.’s Parshall Field, a gem discovered by the operator in the summer of 2006 in Mountrail County, east of the Nesson Anticline.


In two busy years, Parshall and contiguous Sanish Field have grown to some 50 horizontal wells that make more than 16,000 barrels of oil per day. Extraordinarily good Bakken wells continue to expand the accumulation, which now covers nearly eight townships. Estimates of recoverable oil are 150 million barrels at its current size, but limits are not yet defined downdip or along strike.


The first discovery in the area was made at Ross Field, in north-central Mountrail County. Michael S. Johnson, independent geologist, and Henry H. Gordon, president of Strata Resources, both based in Denver, put together a 6,000-acre prospect at Ross.


“I looked at electric logs and completion cards, and noted that several wells had some noncommercial Bakken oil recoveries,” says Johnson. “The Gulf Nelson Farms well, drilled in 1982, was a lookalike to Elm Coulee Field, and that’s what drew me to the area.” The duo sold the deal to a couple of private independents, who partnered with EOG Resources to drill a horizontal Bakken well in late 2005. A twin to the Gulf well, the #1-24H Nelson Farms, in Section 24-156n-92w, flowed 155 barrels of oil, 100,000 cubic feet of gas and 102 barrels of water from a single 4,000-foot lateral.


The Ross discovery wasn’t unusually fine, but it inspired the prospectors. About 25 miles south, Johnson and Gordon put together another idea, this one much larger in size. “Logs on a dry hole in this area also looked like logs in Elm Coulee,” says Johnson.


The geologist was amazed that the acreage on his idea was unleased. “I couldn’t fathom why it was all open. I used to walk around the block and wonder what was wrong with it—why didn’t anyone own it?”


Tulsa-based geologist Bob Berry joined the pair and put up most of the leasing capital. The group acquired 38,000 acres, some of it for as little as $3 an acre.


Johnson showed the prospect to some 15 companies. A common critique was that the acreage wasn’t fully within the Bakken’s oil-generation window. Most explorers believed it was too edgy, bordering on thermally immature Bakken.


EOG eventually bought 75% of the deal, and Berry kept a quarter. In early 2006, EOG drilled its #1-36H Parshall. Pressures were so high—gradient of 0.7 psi—that the company was only able to take the lateral out 1,200 feet into the Middle Bakken before the well blew out. It was completed making 463 barrels of oil per day.


EOG immediately began to drill offset wells, and results climbed as it fine-tuned its drilling techniques. (Berry sold his interest to Whiting Petroleum when the drilling flurry began.) These are monster producers: Wells with initial potentials of up to 3,630 BOE per day have been completed in Parshall Field.


According to EOG, a typical single-lateral producer at Parshall has a measured depth of 15,000 feet, can be drilled for $5.25 million, and can tap gross reserves of 900,000 barrels of oil. Oil in place is 9 million barrels per section; the field is being developed on 640-acre spacing. The company orients its laterals at right angles to the regional fracture trend, which runs northeast-southwest. Stage fracs along the laterals are employed as well.


One of the truisms about resource plays is that they don’t behave like conventional reservoirs. At Parshall, the boundary between thermally mature and immature Bakken forms part of the updip trap, says Johnson. “That’s why we had so much trouble selling this. Parshall is different than any Bakken field in North Dakota.”


Current thinking not yet universally embraced holds that Parshall’s oil was generated in place and that the area is near the immature boundary. Parshall appears to be a new type of trap, and it has broad implications for explorers working in other areas and other resource plays. Fundamental concepts are being eagerly reevaluated by geologists.


“This Bakken play is the best thing that’s happened to North Dakota’s oil industry since discovery of the Nesson Anticline fields,” says Johnson.

Prime location
Whiting Petroleum Corp. has an enviable position of some 96,000 net acres in the eastern Bakken play. Its 13,000 net acres in Parshall equate to an average 20% interest; in Sanish, its interests range from 80% to 100%.


“We were an early participant in the development of Elm Coulee in Montana’s Bakken play, but we didn’t have much acreage,” says James Volker, president and chief executive. “So we put our people to work looking for similar geologic conditions, and areas where the Bakken was mature enough to have oil in the expulsion stage.” The Sanish area stood out, thanks to an old well log that exhibited a thick section of high-resistivity rocks in the Middle Bakken.


Sanish is similar to Parshall, but not identical. Both the entire Bakken interval and the crucial Middle Bakken reservoir are thicker in Sanish, and the field is firmly in the oil-generation window. Wells in Sanish recover between 350,000 and 900,000 BOE each. Initial rates on Whiting’s wells can easily top 1,000 BOE per day. Its best completion announced to date is its #11-27H Liffrig, which came onstream earlier this year at 2,530 BOE per day.


The company has settled on a development plan of two single laterals, oriented northwest-southeast, on each 1,280-acre unit. A Sanish Field well costs $6 million, compared with 640-acre Parshall wells that run $5.2- to $5.5 million apiece. Whiting saves $10.4- to $11 million in drilling costs by using two vertical holes and long laterals on 1,280-acre units, versus four vertical holes and laterals on 640-acre units.


“Each field is unique and requires its own approach,” says Volker. “Sanish has thicker Middle Bakken and more matrix storage than Parshall, and it’s less intensely fractured.”


For completions, Whiting runs an uncemented liner in its laterals, which typically extend nearly 10,000 feet across two sections. It uses swell packers and sliding sleeves. “It’s a great mechanical advancement,” says Jim Brown, senior vice president. “The external packers and sliding sleeves allow us to frac up to 11 zones in a 24-hour period.” Per well, its stimulations consist of 2 million pounds of sand and 20,000 barrels of low-concentration gel.


In 2007, Whiting drilled 33 Bakken wells. This year, it plans 56 wells in Sanish,­ of which it will operate 36, and it will participate in 50 to 60 wells in Parshall Field. Its North Dakota capex will be $302 million, 40% of its total 2008 budget.


At present, the company runs five rigs at Sanish. It will shortly ramp to seven rigs, and will finish the year at nine. “Each rig can drill about six wells a year, so over three years we’ll operate 128 wells,” says Volker. “In addition, we may drive another wellbore between existing pairs to reduce spacing to 320 acres.” Whiting’s locations total 180 at two wells per 1,280-unit; infill drilling would naturally increase that inventory markedly.


Whiting emphasizes infrastructure, and it has been enhancing its ability to build gas-processing plants. The company is constructing a gas plant at Robinson Lake, south of Stanley. Initially, the plant is processing 3 million cubic feet a day. By the first quarter of 2009, capacity will reach 33 million a day. Out of each million cubic feet, it will strip approximately 150 barrels of gas liquids.


“This is a great opportunity for us to process our own gas, and also process some gas for others.” Additionally, the company is constructing pipelines to Stanley to take gas to Williston Basin Industries and oil to Enbridge.
“We want to eliminate flaring in the field. The day we frac, we want to be able to send our gas through to sales,” says Brown.


The company’s Bakken production is steeply inclining. In the first quarter of 2008, Whiting’s net production from Middle Bakken in Sanish and Parshall totaled 3,344 BOE per day, a 92% increase from fourth-quarter 2007. Net production in March reached 4,153 BOE per day, and more good news is expected in its second-quarter results.


“We’re very happy with our position in the Bakken,” says Volker.

North Dakota focus
Another firm tied strongly to the Bakken play is Austin, Texas-based Brigham Exploration Co. “We’re very excited about the Bakken, and we feel very fortunate to be involved in it,” says Bud Brigham, chief executive and president.


Brigham entered the play in 2005. “We came out of a board meeting with the charge to find unconventional plays that would complement our successful, but often choppy, conventional drilling program. Our goal was to bolt on a deep, predictable inventory to provide more consistent quarterly growth for our shareholders in both production and reserves,” he says.


The company evaluated all the major unconventional plays in the U.S., and the Bakken rose to the top.


“We were attracted to the Bakken’s potential economics and substantial resources in place, and the associated option value that it provided. It became our first and most significant commitment to an unconventional project.”


Brigham had been working in the Williston since the mid-1990s. It initially played Red River, and had enjoyed some success. It lined itself up with a consultant who had been involved in the early days of Elm Coulee, and purchased 45,000 net acres in Williams and McKenzie counties in western North Dakota. The main geological criterion was porosity development in the Middle Bakken.


In 2006, the company drilled three long laterals that ranged from 8,000 to 9,000 feet in length. “These were prior to the implementation of staged-frac technology in the play,” says Brigham. A single frac was placed on each lateral.


Results were not sterling. Two of its wells came on at about 200 barrels per day. “We were disappointed in those early results, but production from those wells has held up better than we expected.” Ultimately, each well should make between 100,000 and 165,000 BOE.
The company pressed onward. It continued to aggressively add leases, and at present holds nearly 300,000 net acres. Its prime holdings are 88,000 net acres in Mountrail County, which it entered in 2007 through a 3,000-net-acre joint venture with Northern Oil & Gas Co.
Brigham segments its Mountrail holdings into three areas: Parshall/Austin area, with 8,700 net acres; Ross, with 27,000 net acres; and Stanley, with 5,800 net acres. It has one rig working continuously, and it will likely pick up a second rig later this year. Its 2008 program is currently set at seven operated wells, but if it takes on another rig, the figure will rise to 10 to 15. “We’re not a first mover, but we were out there early. To a large degree, we’re following the tried-and-true methods pioneered by other operators,” says Brigham.


Its nonoperated activity has also accelerated dramatically. Its latest estimate is that it will be involved in 44 nonoperated wells, typically with smaller working interests ranging up to 25% per well.
“In 2008, we could be involved in 56 wells, potentially proving up approximately 100 locations,” says Brigham.


Meanwhile, the company has been acquiring acreage in eastern Montana, targeting Middle Bakken dolomite porosity and also Red River features. Brigham holds 100,000 net acres in Montana, and has drilled two consecutive Red River discoveries in that area.
Neither has it forgotten about its original play. The company recently added 48,000 acres west of the Nesson, which raised its total position in Williams and McKenzie counties to 99,000 net acres. It has reentered one of its original Bakken horizontals in that area. It sidetracked the hole and used swell packers and multiple stages to stimulate the lateral.


“We’ll have some news to report on that soon, and we’re optimistic that this will improve our results and make our acreage west of the Nesson economically viable,” he says.


Brigham expects to be busy in the Williston for many years. Despite the fine wells operators are making, only 5% to 15% of the Bakken’s in-place oil is being recovered. “We fully expect that improvements in technology—such as stimulations, refracs and secondary recovery—will allow us to get more of that oil out of the ground. There is a lot of option value over time.”


Furthermore, the Williston is a multi-pay province. “We think the Three Forks is just one example, but may be the best example, of the kind of expansive potential that the basin offers.” The company is in the planning stages for a consortium that will drill a Three Forks well in Mountrail County.


“We are a small company, but we have nearly 300,000 net acres in the Bakken. Relative to other public companies involved, we think we’re the company most leveraged to the play. If investors like the play, they need to take a look at us.”

Long-time player
St. Mary Land & Exploration Co. was an early participant in Elm Coulee Field through its subsidiary, Nance Petroleum. St. Mary was quite pleased when XTO Energy Inc. recently purchased Headington Oil’s interests in Elm Coulee and the Bakken play for $1.85 billion in cash and stock.


“Having XTO come into Elm Coulee as an operator is very valuable to us,” says Jay Ottoson, St. Mary executive vice president and chief operating officer. “If we apply that valuation to our 113,000 net acres in the field, it’s a really big number.”


Like other Elm Coulee operators, St. Mary moved into North Dakota several years ago to test the Bakken. “Our early results in North Dakota using Elm Coulee technology were not very good,” he says.


The company currently holds 37,000 net acres in North Dakota, including 25,000 acres on the border of Mountrail and Burke counties in its Powers Lake and Stillwater areas, and 12,000 acres on the Nesson Anticline.


“We think that the technology that EOG brought into the basin has opened the Bakken up across a very large area. It makes our areas much more prospective,” he says.


Outside of the Parshall area, St. Mary sees the Bakken as a cost-driven play. “The industry should be able to drill wells across wide areas if costs are reasonable.”


This year, St. Mary plans to operate two to three horizontal Bakken wells in North Dakota. It’s also taking its wells down to the Three Forks, which it believes could be present beneath its acreage, and it is participating in a number of nonoperated wells.
Its first new-technology Bakken well is drilling in its Powers Lake project in Mountrail County. “We’re going to spend the money to do everything we can to make a well,” says Ottoson. It is a 640-acre test, and the company plans to use an external casing packer completion with sliding sleeves.
For 2008, it will keep that rig busy in the Bakken. “We’ll ramp up next year if this year’s program works. We see a lot of upside in the Bakken.”

West of the Nesson
Another operator that’s reconsidering its Bakken potential is American Oil & Gas. The Denver independent entered the play three years ago, and drilled a multi-lateral well in 2006 on the 90,000-gross-acre Goliath Block in Williams and Divide counties. The block is operated by Evertson Operating Co., a private firm based in Kimball, Nebraska. American owns 32,000 net acres; its other partners are Denver-based Teton Energy and Australian firm Sundance Energy.
“Like others, we brought over technologies that had been successful at Elm Coulee,” says Andrew Calerich, president. The company made a producer, but the 160-barrel-per-day production rate was disappointing. The well had three laterals, and one of the fracs jumped into the Lodgepole.
“We’re evaluating the geology on our acreage again. We want to figure out where to drill our next well.” The block is directly west of the Nesson Anticline, and several operators, including Continental and Hess Corp., are active on adjacent blocks.
Happily, American and its partners have Red River potential at Goliath as well. It has participated with Whiting in successful Red River drilling, and it will drill a Red River target this summer on a prospective trend that runs north-south across its block.
A common conception holds that the Nesson Anticline was positive during Bakken deposition, and that it acted as a barrier to sand and reworked carbonate deposition. Bakken workers have believed that clastics were prevalent on the eastern side of the anticline, but that they were not deposited on its western side. That’s crucial, because the sandy dolomitic facies comprises the main reservoir rock in the Middle Bakken. Where that’s not present, basinal rocks are present that are not nearly as prolific.
“The Middle Bakken is very complex,” says Peter Loeffler, American vice president, exploration and development. “It’s a very fine-grained dolomitic siltstone, and we see evidence for that facies in our area. We think clastics did cross the anticline in Bakken time.”
Completions are the key for making economic wells in the Goliath area, he says. “I’m confident that we do have reservoir in our area, and we think good completions will open up the Middle Bakken reservoirs that are not naturally fractured.”
American and its partners expect to start drilling for Bakken by year-end.

Southern reaches
The Bakken has even attracted foreign firms to North Dakota. Sundance Energy, formed in late 2003, holds approximately 16,000 net acres in the play, mainly concentrated in two areas.


In its South Antelope prospect, in McKenzie County south of Antelope Field, it holds some 4,000 net (25,000 gross) acres within an area of mutual interest with private New Orleans-based operator Helis Oil & Gas. Sundance’s first four wells at South Antelope came on production recently, and it has an additional well working on completion and a sixth well drilling.


“We participate with Helis with everything they do in South Antelope,” says Jayme McCoy, Sundance’s Denver-based managing director. Sundance’s interests range from 50% to 7%. “Helis has a rig under contract, and this will be a good driver for our activity in the near term.”


In this area, Helis has drilled laterals in both the Middle Bakken and Three Forks-Sanish intervals. “We have one well that produces from dual laterals, and we’ve had good results in both zones,” he says. Going forward, the partners plan single-lateral completions. Sundance’s best well to date is #16-14H Jones, which had an initial potential of 971 barrels of oil per day and produced an average of 400 barrels a day during its first 15 days onstream.


Adjacent to South Antelope, Sundance owns 100% of approximately 7,500 acres in its Phoenix prospect, in McKenzie County on the Fort Berthold native American reservation. This block lies on the southern end of the Nesson Anticline. Industry interest is quite high in this position: field reports indicate that private operator Peak North Dakota LLC has achieved rates of around 1,000 BOE per day at its #9-24H Tekakwitha, drilled about four miles northeast of Mandaree and within six miles of Sundance’s Phoenix project.


Sundance has secured a permit on its #21-30H Chase and is building location on that well. “We’ll operate this project ourselves,” says McCoy. “Permitting has been very challenging, so we have started permitting on three additional wells to meet our 2008 drilling goals.”


Each well on the reservation requires an environmental assessment, which slows the permitting processes. “Reservation land is overseen by the Bureau of Indian Affairs and Bureau of Land Management, so we’re dealing with the federal layers of administration, in addition to the normal state requirements.”


Services are also in short supply. Drilling rigs are difficult to come by, and tubulars, such as casing, tubing and liners, are expensive and not readily available. “The high oil prices are great, but this area is extremely competitive and it can be difficult being a small operator in this environment.”


Nonetheless, the major hurdles appear to be behind Sundance, and it’s looking forward to a 2008 drilling program of three to four operated wells at Phoenix, and 13 to 15 nonoperated wells elsewhere in the basin.


Additionally, Sundance owns a 100% interest in its Manitou prospect in Mountrail County. That is in its formative stage; at present, more than a thousand acres have been acquired. Finally, it holds a 5% interest in the Goliath prospect, with partners Evertson, American Oil & Gas and Teton Energy.


Sundance expects meaningful production volumes will begin to flow from its Bakken acreage this year.

Deep background
Not all companies pursue operations, and one firm has built its Bakken strategy around well-positioned lease interests. Wayzata, Minnesota-based Northern Oil & Gas Co. holds more than 60,000 net acres in the heart of the play, with 25,000 in Mountrail County.


The company is led by chief executive Michael Reger, who hails from four generations of Williston Basin lease-brokers. “My family has been leasing lan?d in the basin since the 1930s,” says Reger. “It’s safe to say that a Reger ha­­s leased nearly every acre in the Williston Basin at one time or another.”


In 2005, Reger decided to take the business to the next level, and move it from lease brokering to E&P. In 2006, Northern began to lease in Mountrail County, on the heels of EOG’s Parshall discovery.


The company focused on the core fairway, seeking exposure to drilling activity, and that strategy has worked exceedingly well. “We have been permitted into more than 75 wells with various operators, and our average working interest is about 10%,” he says.
Currently, Northern is participating in 10 wells, and it has another dozen spudding within a month. If activity continues at its present pace, its entire acreage position could be drilled over in two years.


The company has about $15 million in cash, some $14 million in outstanding warrants, and no debt. “We have a nice war chest to meet our cash calls and feed our aggressive acreage acquisition budget. Our production is growing quickly.”

Bakken future
Lots of companies are working North Dakota’s Bakken, and observers have speculated that the rig count could reach 100 by year-end. So far, operators using horizontal wells and multi-stage stimulations have been making excellent wells flung far across their holdings.


Still, although the Bakken is present and thermally mature over a marvelously large area, it’s far from a homogenous formation. Many unknowns remain: the importance of local and regional tectonics, fracturing from oil generation, salt dissolution, overpressuring and facies changes are among the immediately obvious questions.


What is clear is that the target is compelling. Unquestionably, enormous volumes of oil are held within the cryptic formation. Time will tell if the industry’s best technologies can unlock a good part of the Bakken’s potential.

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