Shaletech: Bakken/Three Forks

Having thawed out from a historically brutal and prolonged winter, the expanding fairway of the Bakken-Three Forks play is on pace to deliver record production, bolstered by a beefed-up infrastructure that has sunk differentials to low single digits.

“In North Dakota, we fought a prolonged subzero temperatures period, including the coldest February since 1936,” said WPX Energy Inc. President and CEO Clay Gaspar, who noted the company managed to keep wells producing, even as temperatures fell to –40°F across the Williston basin. One of the known casualties of the stubbornly bitter cold, which extended well into the first quarter, was Whiting Petroleum Corp.’s Redtail field, where wellhead freeze-offs cut quarterly production 16%, to an average 14,925 boed.

Fig. 1. May-to-June Bakken oil and gas production is expected to increase by 16,000 bpd and 22 MMcfd, respectively. Source: EIA.

Nevertheless, WPX, Whiting and their peers have rebounded nicely, with the U.S. Energy Information Administration (EIA) estimating that the Bakken, and underlying Three Forks, will separately or conjointly deliver more than 1.42 MMbopd in June, Fig. 1. That would outstrip the previous high of just over 1.40 MMbpd produced in the North Dakota fairway last December, according to the state’s Department of Mineral Resources (DMR).

The increased oil production has been met with an enlarged takeaway infrastructure, highlighted by the North Dakota-to-Illinois Dakota Access pipeline network, with newly expanded capacity of 570,000 bpd. Regional refining also has helped reduce the reliance on rail and truck takeaway, and significantly lowered price differentials relative to the West Texas Intermediate (WTI) benchmark. Widening differentials resulting from refinery and infrastructure interruptions during the worst of the epic freeze narrowed considerably later in the first quarter, dropping to below $2/bbl in some cases.

Fig. 2. Hess is expanding the capacity of the in-basin Tioga Gas Plant from 250 MMcfd to 400 MMcfd. Image: Hess Corp.

The EIA, likewise, expects gas production to continue its steady rise and hit a record of 2,786 MMcfd in June. The increase in associated gas production can be attributed to the evolving build-up of in-field processing, gathering and takeaway capacity (Fig. 2), driven largely by the 88% gas capture regulation that the North Dakota Industrial Commission enacted to reduce flaring. “As we move through the second quarter and into the third quarter, I think we’ve got some additional takeaway capacity and processing on the gas side that should help us in the back half,” said Brandon Elliott, CEO of Northern Oil & Gas, Inc., a non-operating leaseholder.

Drilling activity has remained remarkably steady, with an average 57 rigs active in the Williston basin in May, unchanged from a year ago, according to Baker Hughes, a GE company. Many of those rigs are drilling wells with laterals routinely exceeding 10,000 ft and laying the foundation for a wave of high-intensity completions, credited with helping re-delineate the Bakken-Three Forks core. In addition, established operators, for now, are mostly staying pat, as a stingy equity market puts the kibosh on major acquisitions and divestitures in the Williston, which reaches beyond North Dakota, and into Montana and southern Canada.

EXPANDING THE CORE

Six of the active Williston basin rigs, as well as four frac spreads, are under the control of Bakken pioneer Continental Resources, Inc., which saw first quarter production jump 24%, year-over-year, to 199,423 boed. The premier leaseholder, at 797,000 net acres, Continental completed 55 gross (40 net) operated wells in the first quarter, with initial 24-hr production rates averaging 2,300 boed (80% oil).

Included in those wells were three strategic step-outs that represented the first tests of the company’s multi-zone optimized completion strategy. The extensions, which reached into lower-cost eastern Montana, where Continental holds more than 50,000 net acres, out-performed legacy offsets by as much as 110% in the first 60 days of production. “We can say that the core of the Bakken, as many like to call it, just got bigger,” President Jack Stark said of the northern, southern and eastern extensions.

The trio average initial flowrates of just over 2,173 boed, while a 3-mi lateral step-out in eastern Williams County, N.D., produced a high of 2,440 boed (80% oil), out-performing a 2-mi offset by 100% over 60 days. The other two wells were drilled and completed in Richland County, Mont., and southern Billings County, N.D., with initial production (IP) rates of 1,680 boed and 2,400 boed, respectively.

Hess Corp, likewise, will operate a six-rig program this year—up from 4.8 rigs in 2018—and drill 170 wells, representing a 42% increase over last year. Despite February’s “severe weather conditions,” the company managed to drill 38 wells in the first quarter with 25 new drills put online, helping lift production to 130,000 boed, a 17% increase over the year-ago quarter. Hess will take advantage of a warmer second quarter and drill around 40 wells, with 45 put on production.

The New York-based independent plans to run three frac crews in 2019 as part of the transition from once-standard 60-stage sliding sleeve design to high-intensity plug-and-perf completions. COO Greg Hill said that around 25 wells outside the core areas are on tap for this year, mainly to establish specific completion practices for different portions of the play.

At 554,000 net acres, the Bakken-Three Forks represents Hess’ largest operated asset, where the company has targeted 2019 net production of net production between 135,000 and 145,000 boed.

PARENTS PERK UP

Whiting Petroleum credits the shift to optimized Generation 4 and, more recently, Generation 5 completion strategies with expanding the core of a more than 470,000-net-acre leasehold, while a sweeping in-fill development campaign has provided an unexpected bonus: increased production from parent wells. The surprising dividend prompted the company to take another look at some 1,500 Bakken wells completed earlier.

“What I did not expect is that we could have a positive effect on parent wells,” said President and CEO Bradley Holly. “But, we are, in fact, seeing some impressive uplifts on existing production rates on older wells that we believe are more than just flush production. If we are offsetting a Gen 1 or Gen 2 completion that was seven to 10 years ago, we think we have a great chance of possibly stimulating that.”

The since-restored Redtail weather interruption notwithstanding, first-quarter production was up 10% from a year ago, averaging 113,215 boed. Whiting plans to run five rigs and three completion crews this year, spread out among its eastern, northern and southern Williston assets. Current guidance calls for the drilling of 132 gross wells, with 154 wells scheduled for completion and 146 gross wells put on production. The 2019 program will extend into Montana, where the company holds 55,000 acres, where two wells were drilled as part of an evaluation of the southern portion of the Williston leasehold.

This year, Whiting began the transition to geologically optimized Gen. 5 completions which, along with cemented liners and diversion technology, features reduced cluster spacing, 220-to-280-ft stage spacing and proppant loading of 635 to 900 lb/ft. Holly credits the latest generations of completions and in-fill drilling in established fields with expanding the Bakken-Three Forks core across the basin. “We’re seeing core-like results in areas that were non-core,” he said.

Elsewhere, WPX Energy battled through the savage winter to increase first-quarter production to an average of 63,100 boed, up 60%, compared to the same quarter last year. The company is running three rigs on the 85,000 net acres under control on the Fort Berthold reservation.

Recently completed two-well and four-well pads delivered cumulative 60-day oil production of 585,000 bbl, while a third four-well pad had produced an aggregate 495,000 bpd after 90 days on line.

WPX said that following “market imbalances” in the fourth quarter that drove differentials to around $10/bbl, Williston margins strengthened considerably midway through the first quarter, dropping closer to $2/bbl, WPX said.

OTHER ACTIVITY

As of May 14, XTO Energy, Inc., was running six rigs across the roughly 486,000 net acres it owns, according to the North Dakota Department of Mineral Resources’ active rig list. The ExxonMobil subsidiary said last year that it intends to double oil production to around 200,000 bpd over the next two years.

Fig. 3. One of the Equinor Bakken pads contributing to production of around 63,000 boed. Image: Ole Jørgen Brartland, Equinor ASA.

No stranger to inclement weather, Norway’s Equinor ASA exited 2018 averaging 63,000 boed, up from 57,000 boed over the year prior (Fig. 3), according to federal filings. Equinor was running a single rig in May on its 236,000-net-acre Bakken/Three Forks leasehold.

EOG Resources, Inc., also is operating one rig in 2019, drilling two wells in the first quarter. Completions have been deferred until the summer, as part of its seasonal development program, which will include 20 net completions this year.

Marathon Oil Corp. averaged 92,000 boed, net, in the first quarter, with 29 gross wells hooked to sales lines at average 30-day IP rates of 2,500 boed, with activity concentrated primarily on the Middle Bakken Myrmidon asset in McKenzie County. Marathon said it recently expanded its roughly 260,000-net-acre holding with a small bolt-on acquisition and additional leasing, which added over 50 new drilling locations.

“NOTHING’S TRADING”

Bolt-on leases are about the extent of Bakken deal-making these days. Despite what some say are attractive fundamentals across-the-board, the Williston basin inexplicably remains on the outside looking in. “Lots of people would like to expand footprints in the Williston. You have great differentials. You’ve got quality oil. You’ve got running room, and highly economic in context of the current price. But nothing’s trading. Nothing’s trading,” says Enerplus Corp. CEO Ian Dundas.

The Canadian-based operator, which controls 65,000 net Bakken-Three Forks acres on North Dakota’s Fort Berthold Indian Reservation, drilled 15 gross wells in the first quarter, with four wells gross turned-in-line. Enerplus plans to average two rigs and one frac spread this year.

In the first quarter, the company brought a three-well pad on production with average completed lateral lengths of 9,600 ft and peak 30-day production rates averaging 1,900 boed/well. Enerplus says it has fixed commitments for some 19,000 bopd, at differentials of $1.90/bbl, for the remainder of 2019.

The Williston M&A picture crystallized in February, when Vantage Acquisition Operating Company, LLC, was forced to abandon plans to buy the 114,100-net-acre asset held by QEP Resources, Inc. The estimated $1.725-billion definitive agreement had been announced two months earlier.

In a Feb. 20 statement terminating the planned deal, QEP cited deteriorating commodity prices as making it “unlikely that the conditions to closing would be satisfied.” For the time being, QEP will continue to operate the North Dakota and Montana asset, which includes the South Antelope and Fort Berthold leaseholds, but with significantly reduced spend, as the company diverts resources to West Texas. Cumulative first-quarter Williston production came in at just under 3.4 MMboe. “Our desire would be to grow our Permian basin (asset) as we take cash out of the Williston,” says Tim Cutt, who was named president and CEO on Jan. 15.

One prospective transaction set to close on July 1 has Northern Oil & Gas paying more than $310 million in cash and stock to buy roughly 18,000 net acres held by portfolio company Flywheel Bakken, LLC. Pre-closing, the Minnesota-based company held around 160,394 net acres and produced 34,598 boed in the first quarter.

Along with the spending flexibility intrinsic of the non-operating model, partnering with a number of operators provides a clear perspective on the aggressive drilling and completion strategies unfolding across the basin.

“We’re seeing some operators do tests, where they’re going all the way up to 2,000 lb/ft (proppant loadings),” says V.P. of Engineering Jim Evans. “They’re drilling 3-mi laterals, and then we’re also seeing some tests of dual laterals. They’ll drill one in the Bakken and one in the Three Forks from the same vertical location.”