Summer has finally arrived in the Williston Basin. On the plains and in the badlands, flood waters are receding, if slowly. Heavy trucks carrying equipment in and crude oil out are rumbling on country roads again. After record-breaking snowfall and a dangerously wet spring muddied roads, collapsed culverts, flooded some wellheads and delayed completions, the industry is working hard to catch up.

It's catching up in a transformative play. The Bakken and accompanying Three Forks formations have kicked North Dakota's economy into high gear, not just from rising oil revenue but from housing starts. The state's unemployment rate is the lowest in the nation; Gov. Jack Dalrymple has granted tax relief to its citizens.

Highway 85 near Williston crosses the Missouri River, which is over its banks.

Last year close to 1,200 wells were drilled, compared to 800 in the previous peak year, some 30 years ago, in 1980. The state is producing more than 342,000 barrels a day.

Some wells drilled six to eight months ago are being completed just now; more frac crews are on the way as operators pick up the pace. By year-end, more than 1,000 wells could be drilled—some say 2,000. The North Dakota rig count peaked at an all-time high of 178 in June, and now hovers around 170, with some expecting it to reach 200 at the close of 2011 (compared to only 49 rigs in 2009). The total includes rigs targeting the underlying Three Forks formation. The Bakken count is also increasing in eastern Montana.

Throughout the play, operators are testing tighter well spacing. Most of Elm Coulee Field is drilled down to 320s and several spacing units in North Dakota have been drilled down to 320 already. For the six months ended June 30, the state had granted 233 drilling permits in McKenzie County, 157 in Williams County, 146 in Mountrail and 144 in Dunn. Another 54 were granted in Roosevelt County, Montana.

Longer term, it is clear the Bakken will transform U.S. oil supply.

"Our best-case production forecast to year-end 2012 is 530,000 to 550,000 barrels a day from the Bakken and Three Forks, not counting production from Red River or other traditional formations," says Siddhartha (Sid) Sen, upstream analyst for the Rockies region for research firm Wood Mackenzie.

"We are assuming the industry can drill around 1,100 wells a year, so at least 11,000 wells should be drilled in 10 years, with production of 1 million barrels a day by 2017."

Based on type curves and other factors, WoodMac now estimates the breakeven hurdle is $46 to $48 per barrel, but the firm was updating its well profile at press time. RBC Capital Markets estimated an internal rate of return of 50% for most Bakken wells at current oil prices.

If a typical Bakken well costs $8 million, the area in which wells can generate revenue above capital cost is "perhaps 2.5 million acres," says a Bernstein Research report. "It is worth noting that the analysis excludes the Three Forks, which underlies much of the Bakken. This provides potentially double the locations per section," says senior analyst Bob Brackett.

It is still early in the play, so industry needs time to drill more wells and gather longer-term production data. Obviously, well results will vary from county to county and operator to operator based on geology and completion techniques.

"We are looking at data from about 1,800 wells drilled and revising our EURs (estimated ultimate recoveries) upward, but in some places they are as much as 680,000 barrels of oil equivalent per well," WoodMac's Sen says.

No wonder long-established players and newcomers are attacking the play. By some counts, 31 public companies and 15 or 20 private ones are involved.

Sixty years ago, Hess Corp. opened this basin with the first vertical oil well, drilled at Tioga, North Dakota. Now, it holds the largest position, close to 1 million acres, thanks to that legacy—acquiring American Oil & Gas Inc. and privately held TRZ Energy LLC for a combined $1.5 billion last year.

On the other end of the scale, relative newcomer Triangle Petroleum Corp., based in Denver, "was desperate" to get into this play, says CEO Peter Hill, who joined the company last year. "We're in about 40 wells in various stages of drilling, completion or production. We plan to look, listen and learn, then apply that to our own wells. We hope to operate our first well in October, in McKenzie County. We have the rig."

Size of the prize

Thanks to horizontal multi-stage fracs in the Bakken and Three Forks zones, operators continue to drive up EUR estimates for their wells and drive down costs. Since technologies enable more oil to be recovered, the U.S. Geological Survey has gone back to the drawing board, as industry seeks an update to its 2008 mean estimate of 3.65 billion barrels of technically recoverable oil and 1.85 trillion cubic feet of associated natural gas. Results are expected in 2013.

Optimistic operators on the ground are not waiting around. "When you look at oil production here from the 1950s to today, it's about 2 billion barrels. Compare that to this new generation of wells, and that dims in comparison—that will be 10% of what we'll end up producing from the Bakken," says Harold Hamm, chairman and CEO of Continental Resources Inc., which owns 855,000 net acres and has 24 rigs running. Hamm, one of the most vocal champions of the Bakken, believes the ultimate potential is closer to 20- to 24 billion barrels.

Brigham Exploration Co. will add a 12th rig by first-quarter 2012, says CEO Bud Brigham.

Bud Brigham, CEO of Brigham Exploration Co., says the company's internal assessment puts it at 10 billion barrels. Brigham alone has 18 years of derisked, net locations remaining, he told the Hart Energy Developing Unconventional Oil (DUO) Conference in Denver this past May. Earlier, in March, the company reached a milestone: 10,000 barrels a day of Bakken production. It is running 10 rigs now and going to 12 by first-quarter 2012.

"What gets me is how staggering this is. This play is 12,500 square miles, or 8 million acres from eastern Montana to Minot," says Triangle's Hill, who was with BP for 23 years, at one time its chief geologist. "I think when we improve the technology, when all is said and done the Bakken will be well and truly bigger than Prudhoe Bay. I think Harold is right. Here we are, 150 years after oil was discovered in the U.S., and we've just found America's biggest oil field."

The effect on North Dakota's small towns is huge, bringing new challenges to city and county officials. Studies by the state show as many as 8,900 affordable housing units need to be built in the towns surrounded by the oil rush. The North Dakota legislature is investigating tax incentives and other financial tools to help construction along. The Lutheran church is converting an old hospital into apartment units. Halliburton brought in a 300-man camp left over from the 2008 Vancouver Olympics.

In Minot alone, construction companies built 600 new homes and 1,000 apartment units in the past three years—only to see those gains offset by the tragic flooding in June, which left 2,500 homes under six feet of water from the rampant Souris River. At press time, the North Dakota State Fair was cancelled due to two feet of standing water at the fairgrounds in Minot, dealing the area another blow.

The Souris River inundated Minot, North Dakota, in late June, putting 2,500 homes under at least six feet of water, and damaging 4,000.

Bakken leaders

Continental Resources drilled its first Bakken well—a vertical—in 1989, so CEO Hamm has seen all the ups and downs since then. It had its share of frac delays this past spring, and a few producing wells were shut-in temporarily because trucks couldn't get through to pick up the oil—but the Oklahoma City company still is on the fast track to double-digit production growth this year.

At press time, industry was waiting on second-quarter results for all the Bakken producers, but in the first quarter, despite the harsh winter, Continental reported Bakken production of 25,500 barrels a day, up 67% year-over-year.

"We had some good things on the other side of the ledger," Hamm says. "The Hiland Partners gas plant near Watford City was up in mid-June and we're running about 30 million a day through it. This fall they will bring in a second skid and take that up to 85 million." The plant handles third-party gas as well.

Hamm thinks 70% of Continental's acres have been derisked, "but you have to get out ahead of it and ask, where is the rest of it? This thing keeps growing in areas you wouldn't expect. We have a producer in the Second Bench of the Three Forks formation and I think other people are looking at that, too."

Continental has been successful because it's been drilling in North Dakota for 22 years, it has leases all over the state ( north and south of the Missouri River and east and west of the Nesson Anticline), and it is using the latest technology, regularly drilling four wells per 1,280-acre unit on its trademarked ECO-Pad system.

However, Hamm says he still considers acreage north of Elm Coulee Field in Montana to be in the exploratory stage, even though the latter was discovered in 2000 with early-stage horizontal drilling. The play is expanding north of there now.

The company reports an EUR of 518,000 barrels of oil equivalent (BOE) per Bakken well. "We…expect the number to go up significantly, with commentary on current wells in the 700,000-BOE range," says a Tudor, Pickering, Holt & Co. report. "CLR is currently running 24 rigs in the play and doing 24 to 30 frac stages on every well, with costs ranging from $7.2 million for a 24-stage well to $7.8 million for 30 stages (with broader ranges seen between $6.9- and $8.1 million)."

Hess Corp. has successfully drilled nearly 50 dual-lateral wells, says David McKay, director of the Hess

Amerada, the predecessor of today's Hess Corp., opened the Williston Basin in 1951 with its Clarence Iverson #1, and 60 years later, Hess finds itself leading the basin with almost 1 million acres under scrutiny.

The company is producing about 30,000 barrels a day including the two acquisitions—but this number lags its planned production, due to the weather. "It was the worst winter in North Dakota history, and that's saying a lot," says David McKay, Houston-based director of the Bakken project team. Nevertheless, Hess employees moved into a new office building in Minot the very same week the river crested in late June, flooding the city.

Despite the challenges, Hess will likely meet its target of just under 200 wells completed by year-end. Drilling is not the problem; fracing is, since crews have to move every five or six days and roads have been impassable. "We have adequate resources, four and a half dedicated frac crews, but it's a road problem. We probably had close to 40 wells that still need to be fraced," as of early July.

Hess is drilling single-lateral horizontal wells at the moment to hold acreage, but beyond 2011, it will consider dual laterals to reduce costs and the rig footprint, as well as the speed of execution. It has already drilled close to 50 dual laterals, but since the TRZ deal closed, it needed to speed up the action to hold acreage.

"It can be tricky, but we feel we've gotten it to be highly repeatable. We landed our casing so we can come back in and drill the second lateral later on. And, we are looking at other configurations: either we complete both laterals in one formation (Bakken or Three Forks), or we can complete one lateral in each zone."

Hess is a leader, along with Whiting Petroleum Corp., in the use of sliding sleeves for fracs. "We are successfully drilling with 38 frac stages, but evaluating the optimum number to use." It's also looking at two pilot projects to determine if tighter well spacing is appropriate to drain the 1,280-acre unit, and it may increase the number of frac crews it has on call.

Continental Resources CEO Harold Hamm, third from left, and his team dedicated this marker for their Robert Heuer 1-17R in Divide County. Drilled in 2004, it was the first modern-era Bakken well horizontally drilled and fraced with multiple stages.

Hess has drilled a couple of wells near the Canadian border in an effort to expand the play north.

"From a technical and economic standpoint, it is pretty amazing," says McKay of the Bakken. "We take North Dakota very seriously. This is really a precursor to having a much larger unconventional resource business around the world. We hope to carry our technology and methodology to other parts of the U.S. and around the world."

Forty stages

Whiting Petroleum Corp., the No. 2 oil producer in North Dakota, is pursuing a vigorous campaign this year, aiming to drill 82 wells in Sanish Field, 48 in the Lewis and Clark area, 11 at Hidden Bench, one at Missouri Breaks, and eight in other fields in the Bakken and Three Forks plays.

"What we are doing in areas outside of Sanish and Lewis and Clark, is testing this year so we can put them into development mode next year," says CEO Jim Volker.

"At Missouri Breaks and Hidden Bench, for example, we are drilling 12 wells this year, but because results appear to be good, we could have as many as three or four rigs in that area next year, drilling at a pace of 50 wells a year."

Whiting Petroleum Corp.’s Bakken team has just moved into a new building near its Sanish Field, says CEO Jim Volker.

Despite muddy roads and heavy rains that left up to 45 operated and nonoperated wells waiting on completion as of early July, Whiting "should be caught up on the operated wells in the fourth quarter," says Volker.

"Our projections show that the third quarter could be a good one for us, as far as getting our wells on production. The resiliency of our folks up there is something…their total effort to get their own lives in order after the flooding, and also get back to work is inspiring."

The company has two dedicated frac crews and shares another half time, so Volker says it can frac four wells a week.

With 1.1 million acres gross, 700,000 net, Volker says Whiting is concentrated on its Bakken acreage. Its Bakken team just moved into a 35,000-square-foot, two-story building it constructed south of Stanley near Sanish Field, across the road from its Robinson Lake Gas Plant, which is to be expanded to 90 million cubic feet of gas per day by the fourth quarter. It does not need to flare any of its operated gas production from Sanish Field, although some operators are doing so.

Whiting is the only company in Denver to have an electron-scanning microscope installed in its offices, so it can quickly evaluate its cores and adjust its drilling program accordingly.

Likewise, it is one of the only companies to have fraced 40 stages in a single well in one day, by using sliding sleeves. But more stages could be coming, as Baker Hughes in the third quarter will try new technology on a Whiting well that allows fracing to occur along three separate points within a sleeve, so in 20 sliding sleeves, each with three entry points, one could see 60 frac stages.

Operators are expanding the play to the north, west and south

"The better you are at busting up the rock, the more it helps your EUR," Volker says.

The continuing challenge for Whiting is further cost reduction and execution, although it already drills its Sanish wells to total depth in as few as 11 days. It plans to get each of its areas into full development mode in 2012.

"I feel the rig situation is in good shape and as for having enough frac crews, let's just say that Whiting is, quote, 'all over it.'"

Another advantage Whiting has, in Volker's opinion, is that early on, it identified stratigraphic traps no one else had tested, and thus got its acreage in hand for $50 to $500 an acre, as opposed to some recent asset sales and corporate deals that worked out to $2,000 to $10,000 per acre.

"We are still leasing in North Dakota to fill in our position and add on the edges of the play. Our average cost is $415 per net acre…this keeps our economics highly attractive. It's exciting—the Bakken is a company-maker for us."

A Bakken pure play

It certainly is for Oasis Petroleum Inc., which went public in 2010 as a pure-play Bakken name on the New York Stock Exchange. It has more than 300,000 net acres, three frac crews and will have nine operated rigs by year-end.

Thirty-six frac stages is the company's standard for now, says executive vice president and chief operating officer Taylor Reid. "We're looking at potentially more stages and we think we're seeing a proportional production increase with each stage."

The Houston company's $490-million budget this year devotes $440 million just to drilling. Costs are rising because of more frac stages and service intensity.

Newly public Oasis Petroleum Inc. will devote $440 million to drilling in the Bakken this year, says chief operating officer Taylor Reid.

There's lots of discussion in the industry today about the best way to maximize frac performance, Reid notes. Some companies do plug-and-perf (perforations) completions and others use sliding sleeves. "Sliding sleeves take less time and thus are less costly, although you can do a frac more quickly with sleeves. We think plug-and-perf provides more surety of frac placement. In addition, with plug-and-perf, we get multiple openings through the perfs, for frac initiation between each set of packers.

"The Bakken is a big laboratory right now. All the operators are in a lot of each other's wells, so we get to see what's working."

Reid says the next big wave is to extend production further west in Montana, and south toward Whiting's Lewis and Clark area in North Dakota. Reid also says there haven't been enough tests to the Three Forks yet using the latest completion techniques.

Like most others here, Oasis is focused on holding acreage now. Later, in 2012 and 2013, it will embark on a more sophisticated development plan that determines the best well spacing. "At our current pace, we think we have an inventory of as much as 20 years, based on seven rigs running. That includes three Bakken and three Three Forks wells per 1,280-acre spacing unit.

"The question is, what is the right pace? A fair amount of this works down to $50 or $60 a barrel, depending on where you are in the basin. The challenge for us is to improve recoveries, effectively drain the rock, and bring the costs down so that if you do have an oil-price correction, you can handle it."

Brigham Exploration

Technology has leapt forward and Brigham is acknowledged as one reason why. The Austin, Texas-based company has completed seven of the top 10 wells in the basin so far. At press time, it had drilled 68 consecutive long-lateral wells, with an average IP of 2,800 barrels a day, although some IP'd closer to 5,000 a day. Forty-two of those were in its Rough Rider area alone.

CEO Brigham says keys to the company's outperformance include using geosteering to land the horizontal laterals in the right place, drilling much longer laterals with more frac stages per leg, and using zipper fracs.

A zipper frac allows the company to frac two adjacent wells simultaneously, while increasing the effectiveness of the frac wings. While waiting to set a plug on the first well, the second can be drilling.

Brigham is currently producing about 12,000 barrels of oil equivalent per day, and estimating 500,000 to 700,000 BOE per well. "Even if oil is $55 a barrel, this is still economic," says Brigham. "Our 2010 F&D costs averaged $15.57 per BOE for our operated wells."

It recently increased its 2011 budget to $835.5 million. In addition to increasing its holdings in both its core and extensional Bakken areas, in July it added its 10th rig. At one time it had more than a dozen wells waiting on completion. Two walking (spudder) rigs are expected in early 2012 to speed up the drilling campaign. Brigham currently employs two full-time frac crews, which it estimates can frac eight gross wells per month.

"We are adding a fresh-water pipeline because each frac requires 60,000 barrels of water. This will be more efficient and reduce truck traffic.

"We are using the plug-and-perf method with swell packers. We perf in each stage, and by using microseismic, we can see there are more frac wings going out from the wellbore—thus, more productive wells. The 38-stage frac outperforms versus our 2006-era wells and is giving us a real step-change in the economics," Brigham said at DUO.

Triangle Petroleum

Triangle Petroleum's goal is to secure 100,000 acres, says CEO Hill. "Triangle continues to exceed our expectations in terms of acquiring acreage," says a Global Hunter Securities report. "The company recently picked up 42,000 net operated acres in an area of Montana called the Station Prospect. Management is coy concerning the price and location, since the lease program is ongoing.

"This approach to building the asset base reminds us of 2008, when Brigham began stepping out on the west side of the Nesson Anticline. The area was under the radar for most operators, which allowed Brigham to build their Rough Rider position at relatively discounted prices (until the Brad Olsen well exposed the area). We see Triangle replicating this approach on the Montana side of the play."

Triangle has 72,000 net acres and is within striking distance of CEO Hill's avowed target of 100,000 net acres.

One big lesson from this past winter, Hill says, is not to spread operations too thinly. "If you prepare yourself like a good squirrel, get all your supplies lined up and in place on one road, then you can handle the winter better. Another clever thing is we have swapped acreage and traded with other companies to build a focus. We now have four 1,280-acre units within a few square miles of each other so we can get the benefit of scale, and we can attack the Middle Bakken and the Three Forks development together."

Hess Corp. is building a rail terminal to ship oil out of the area, with a start date of early 2012. Capacity is 70,000 barrels a day.

Montana Bakken

Activity has been accelerating on the Montana side of the Bakken, moving north of the legacy Elm Coulee Field discovered in 2000. "We count over 838,000 net acres identified by 14 public operators on the Montana side of the basin," says an RBC Capital Markets report. Continental Resources and Brigham Exploration appear to be leading the charge here.

In June, the Montana Board of Oil and Gas Conservation approved 200-foot setbacks for 1,280-acre spacing units in Richland County, upon request by Continental Resources. This allows the company to extract more oil from the unit.

Later this summer, six additional Brigham Exploration-operated wells may be completed. Brigham has scheduled one well in Roosevelt County, the other well in Richland County. It was set to ask the Montana board for 200-foot setbacks on several of its leases.

It successfully completed a well 16 miles west of the North Dakota border, the Gobbs 17-8H #1H, in Roosevelt County, with a 36-stage frac. Testing an early 24-hour peak rate of 1,800 BOE per day, the Gobbs is the company's third successful Montana well, and the one furthest west of the North Dakota border. It has 24,400 core net acres in the state's Bakken play.

Continental Resources, meanwhile, reported strong wells on its Montana acreage in the first quarter. The Big Sky 3-35H (95% working interest) was completed with 18 stages using a sliding-sleeve frac system. It tested 1,163 BOE a day. Its Clayton 3-20H (71% WI) tested 1,118 BOE a day.

"The Big Sky and Clayton wells were the company's two strongest Montana Bakken completions in recent years, drilled as 320-acre infill wells in the fairway of Elm Coulee Field," said CEO Hamm.

Continental is testing several variations on its standard 24-stage, plug-and-perf frac design for Bakken completions and has recently gone to 30-stage fracs per well. All of its Montana wells are using sliding sleeve completion.

"These two were significantly superior to adjacent wells that we had completed in past years with the old open-hole frac technology that was once standard in Elm Coulee," Hamm said in a written statement at the time.

A Minot restaurant thanks the people who have helped this city under siege.

Midstream plans

As Bakken and Three Forks production surges, take-away capacity out of the Williston Basin is a huge concern that both upstream and midstream companies are addressing.

"Our analysis indicates that the current rig count and planned increases could cause take-away constraints of as much as 75,000 barrels of oil per day during fourth-quarter 2011," says a June report from FBR Capital Markets.

"With an additional 370,000 barrels a day of facility additions planned during 2012, take-away capacity should be sufficient through third-quarter 2013, before being short again by as much as 200,000 barrels per day during second-quarter 2014. As such, take-away capacity will need to be continuously added."

EnCap Investments-backed Rangeland Energy LLC broke ground in May on North Dakota's first open-access crude oil marketing hub for storage and offloading, located in Williams County on a 320-acre site. It is a "mini-Cushing" called the COLT Hub, with three 120,000-barrel storage tanks, each 60 feet high, under construction.

The hub will aggregate crude oil produced in Williams and neighboring counties using gathering pipelines and trucks. It will provide crude oil handling and onsite tank storage services as well as access to multiple downstream crude oil markets through the 20-mile COLT Connector pipeline, and railcar loading facilities served by BNSF Railway Co. Workers will load both unit-train and manifest shipments of crude oil to markets throughout North America, including crude oil-receiving terminals along the Gulf Coast.

"The COLT Hub and COLT Connector will offer producers and marketers much-needed terminal services and the ability to access multiple downstream markets," says Christopher Keene, Rangeland president and CEO.

On the natural gas side, consulting firm Bentek Energy LLC says the Bakken gas-processing infrastructure has not kept pace with dramatic growth in rich-gas production, exacerbating the need to flare gas. "An average 18% of gross production from the Bakken has been flared over the last 12 months. Based on Bentek's analysis, Bakken processing capacity will remain constrained until 2014, when the construction of 490 million cubic feet a day of announced processing capacity is completed."

Hess expects to complete its Tioga gas plant expansion in 2012, hiking processing capacity to 260 million cubic feet per day. It also expects to complete a new transload oil facility in first-quarter 2012, initially with 70,000 barrels a day of capacity. Oil will be shipped by rail to a terminal in St. James, Louisiana.

At Whiting's Sanish Field, the percentage of gas flared has varied over time. With the addition of NGL plants this quarter, however, it should be processing all of its produced gas. In the broad area of Lewis and Clark to the south, gas infrastructure varies dramatically. In the Pronghorn area, it will process all its gas when the firm's Bakken Express equipment comes on line in August, capturing 2- to 3 million cubic feet a day. In November, Whiting's Belfield Plant will come on line.

In the Hidden Bench and Lewis and Clark (Grasslands) area, Whiting relies on Oneok to pick up the gas. The latter's large plants at Garden Creek come on in fourth-quarter 2011 and at State Line in the fall of 2012.

Side Bar: Then And Now

Oil and Gas Investor's first cover story, in August 1981, featured the Williston Basin. At that time, the hot play was hosting as many as 160 rigs drilling for the Ordovician Red River. There was a shortage of rigs, lease prices and other costs were rising, and the state geologist was predicting the boom was reaching maturity.

In June 1990, when we revisited the Williston, the Bakken play was emerging. Oil was about $18 a barrel. At that time, operators were hailing the relatively newfangled idea of horizontal drilling, which had recently captured the industry by storm and was making good vertical wells much better in the Texas Austin Chalk. Now they were testing it in the Bakken.

"Don't underestimate the impact of horizontal drilling. It's young, but it's big, and still growing. The technology's ultimate potential is yet to be defined," Investor wrote.

Meridian Oil Inc., later to become part of Burlington Resources, itself later acquired by Conoco, had spudded the first horizontal Bakken well in 1987. By 1990, operators were spending about $1 million to go laterally for as much as 3,000 feet. Multiple frac stages in the horizontal leg were as yet unheard of.

By November 1995, as Investor reported, North Dakota reported production was only 87,000 barrels per day. The Lodgepole play opened by Conoco was the hot target, but was confined to Stark County. Seitel had launched the first group 3-D seismic shoot in the Williston Basin.

But as one manager told us, "A lot of money was spent in the horizontal Bakken for naught, and the same thing could happen in the Lodgepole."