Because of strong results from the Bakken and the Eagle Ford, EOG Resources Inc. bumped its liquids growth target for the year by three percentage points, to 33 percent.
Although EOG is a leading producer in both plays, the Houston-based independent has long been more optimistic about the Eagle Ford of south Texas than the Bakken.
“The Eagle Ford continues to be our 800-pound gorilla in terms of crude oil growth, and we still believe our position is the largest domestic net oil discovery in 40 years and generates the highest direct (after tax rate of return) of any current large hydrocarbon play,” CEO Mark Papa told analysts during a first quarter earnings call in early May.
Still, after several quarters that Papa described as having a “business as usual tone,” the call also found Papa suddenly bullish about the Williston basin. “We’re considerably more optimistic about the next 10 years of this play than we were a year ago,” he said.
So what gives?
Parshall downspacing
Earlier this year, EOG predicted Bakken production would fall in 2012 as the company pulled rigs from the play, but now it thinks production could actually increase slightly.
The optimism comes from several efforts this year.
The first is downspacing.
EOG initially drilled wells every 640 acres at its Parshall field in Montrail County, N.D., but recently has been drilling every 320 acres. The initial results showed not only higher production rates from the newer infill wells, but improved recovery from the initial wells.
The three wells drilled at 320-acre spacing — Wayzetta 156-3329H, 124-3334H and 157-2835H — produced 1,393 barrels per day, 992 bpd and 1,083 bpd with 600 thousand cubic feet per day, 300 mcf per day and 300 mcf per day of associated rich natural gas.
EOG holds a 51 percent to 61 percent working interest in the wells.
The company plans to test the impact of 160-acre spacing on its core acreage, as well as the impact of downspacing on its nearby Bakken Lite acreage, sometime later in the year.
In addition to downspacing, EOG began an enhanced oil recovery waterflood pilot project at Parshall in mid-April and expects to have results by the end of the year.
Although EOG dropped its Parshall field recovery rate estimates to 8 percent from 10 percent after analyzing modeling data, the initial downspacing results suggest 12 percent recovery and a successful waterflood pilot could boost the rate even higher, Papa said.
Success outside core
Second, EOG is reporting success from its non-core fields.
A group of five wells in the Antelope Extension, some 25 miles to the southwest of the core area, confirmed the potential of both the Three Forks and the Bakken in the region.
EOG holds 100 percent interest in the five wells.
And in the Diamond Point/Stateline area of western North Dakota and eastern Montana, EOG completed seven wells with initial production rates between 540 and 1,100 bpd.
The results added 200 drilling locations to the region, according to EOG.
While pleased about its Bakken Core spacing and non-core drilling, Papa acknowledged that Bakken Lite downspacing and the waterflood remain question marks for now.
But EOG is claiming the benefit of a new crude-by-rail facility in St. James, La., that should be able to move 50,000 bpd by June and 70,000 bpd by the end of the year.
The facility allows EOG to deliver Bakken crude to either St. James or Cushing, Okla.
Although the facility will not be fully operational during the second quarter, it received its first shipment of Bakken crude in mid-April, allowing EOG to capture a $15 per barrel advantage from Light Louisiana Crude prices. “Based on current differentials, the best (net present value) for our rail tanker fleet is to move our EOG Bakken oil to St. James and sell our Eagle Ford in the Houston and Corpus Christi markets,” Papa said.
The 1,000-pound gorilla
How does that stack up to Texas?
Although EOG isn’t reporting its rates of return from the Bakken, the economics of its other unconventional plays offer some guidance. EOG is reporting a 40 percent after tax rate of return in the Barnett Shale and a 45-55 percent ATROR in the Permian basin.
But EOG is reporting an 80 percent after tax rate of return from the Eagle Ford.
With improved drilling and completion techniques, and greater operational control, the Eagle Ford is “an 800-pound gorilla developing into a 1,000-pound gorilla,” Papa said.
First, by spacing wells every 65-90 acres instead of every 130 acres, EOG said it increased its potential net recoverable reserve estimate in the play by 78 percent to 1.6 billion barrels of oil equivalent, and also added 3,200 potential drilling locations.
The company is now testing the impact of 40-acre spacing.
Second, as the company and its contractors get better at placing laterals and designing hydraulic fracturing operations, EOG said it is reporting initial productions rates between 2,500 and 3,000 barrels of oil per day in areas that previously produced only 1,500 bpd.
And early next year, EOG plans to conduct a gas injection pilot project to determine whether it can further improve recovery rates in the Eagle Ford above 6 percent.
“The reason we’re not accelerating the drilling of this unusually large well inventory is the technological improvements we’re making. If we’re making better wells than we were a year ago, who’s to say we may not make even better wells a year from now? So why rush to drill wells that may not be technically optimum? We’re closely focused on balancing the present value of this asset versus this technical well improvement,” he said.
The Eagle Ford is also consistent. “We don’t get a lot of geologic or reservoir surprises, and the few surprises we do get are generally more upside than downside,” Papa said.
With a new plant in Wisconsin, EOG is now supplying all its own sand, cutting about $500,000 off the cost of each well, at an annual savings of $300 million. And Papa said EOG has been able to “dodge” transportation bottlenecks in the region, at least for now.
