One year ago EOG Resources Inc. thought Bakken production was on the wane but due to the magic of downspacing — and its success in non-core areas — the company is singing Bakken’s praises once again.
“We’re considerably more optimistic about the next 10 years of this play than we were a year ago,” EOG CEO Mark Papa said during a first-quarter earnings call in early May.
Strong results from the Bakken petroleum system in the U.S. Williston Basin and from the Eagle Ford in south Texas prompted EOG to raise its liquids growth target for the year by three percentage points, to 33 percent.
Houston-based EOG has made no secret of the fact that it prefers the Eagle Ford over 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,” Papa said.
Come togetherEOG predicted Bakken production would fall in 2012 and it pulled rigs from the play.
Today, however, EOG is drafting charts that show an upward trajectory. Downspacing is the key ingredient in a mix of new practices EOG is deploying in the Bakken.
Downspacing has proven to both accelerate and expand recovery.
At EOG’s Parshall field in Mountrail County, N.D., 320-acre spacing has shown higher initial production rates from the newer infill wells. At the same time, downspacing has improved recovery from the initial wells. The synergies have accelerated the return on 320-acre spacing as compared to the company’s previous spacing — a well every 640 acres.
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.
The company plans to test 160-acre spacing on its core acreage and implement downspacing on its nearby Bakken Lite acreage, sometime later in the year.
Also testing waterfloodingAnother test EOG is doing is a waterflood pilot project it began in mid-April to enhance oil recovery at Parshall. EOG expects to have results by the end of the year.
Waterflooding, if successful, would heap an extra spoon of sugar on a projected 4 percent boost to recovery rates at Parshall.
According to Papa, EOG’s Parshall field recovery rate estimates were at 8 percent, but downspacing boosted estimates to 12 percent.
EOG President Bill Thomas said the company is seeing positive results from 160-acre downspaced wells. He added that EOG has completed its first two wells on 160-acre spacings in the Parshall field, and those wells, Wayzetta 022-1509H and Wayzetta 149-1509H, tested at maximum rates of 1,185 and 1,265 bpd, respectively.
“In 2012, we completed 28 net wells in the Parshall field and Antelope areas with a successful 320-acre downspacing program,” Thomas said.
“In 2013, we plan to complete 46 net wells in these same two areas.”
The company’s focus in 2013, Thomas said, will be to further downspace to 160 acres in both the Bakken and Three Forks pay intervals, as well as continue to improve frack efficiency, and to optimize the recovery factor of each play. If 160-acre downspacing proves successful, Thomas said, it will allow EOG to accelerate its development program in 2014 and beyond. Overall, EOG is planning to complete 53 net Bakken/Three Forks wells in 2013.
“The takeaway from our Bakken/Three Forks asset is the wells are getting better with continued success in downspacing,” Thomas said. “The number of potential locations is growing and this provides us many years of high ROR investment opportunity in the play.”
Breaking up is good to doThomas said that advanced fracking technology was another major component in the company’s technical arsenal that was proving effective in boosting output.
“New frack technology is improving our wells in every area of the Bakken/Three Forks,” Thomas said during a Feb. 14 conference call. “In some cases the new frack technology used in our 320-acre downspacing in the Parshall core has resulted in a 30 to 70 percent improvement in cumulative production over the original offset wells on a per foot of treated lateral basis.”
As an example, Thomas cited the company’s Wayzetta 156-3329H, a 320-acre downspaced well completed in 2012 which had a cumulative production of 330,000 barrels of oil in the first 320 days. That well, Thomas said, was steadily producing at a rate of more than 800 barrels of oil per day.
“Our Bakken and Three Forks drilling results during the fourth quarter were outstanding and our 2013 program should be one of our strongest in many years,” Thomas said. “While most of the industry Bakken/Three Forks results are trending downward, EOG results are moving in the opposite direction. In other words, our wells are getting better.”
Overall, EOG’s gross Bakken/Three Forks production at year end 2012 was 62,100 barrels of oil equivalent per day, up from the gross production of 56,400 boepd at the end of 2011. EOG also indicated that its average estimated ultimate recovery, independent of lateral length, was 544,000 barrels of oil per well, while the North Dakota Bakken EUR average is 338,000 barrels.
Happy TrailsVenturing out from its Bakken core area has also paid off for EOG. Some 25 miles to the southwest, in the Antelope Extension, five new wells have confirmed the potential of both the upper Three Forks and the middle Bakken units.
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.
One of the top reasons to anticipate growth in 2013, Thomas said, “is that our drilling program is directed to the Parshall core and Antelope Extension areas, which are some of the best acreage blocks in the play.” He said a recently completed Three Forks well in the Antelope Extension, the Hawkeye 102-2501H, is producing 2,945 bpd. Another recently completed Antelope Extension well, the Hawkeye 01-2501H, a Bakken formation well, is producing 2,444 bpd.
Working on the railroadEOG has made investments to increase Bakken production, but new production won’t add to cash flow unless it has a cost-effective path to market. The company expects railroad tankers to continue to ease the shortage of pipeline capacity out of the Bakken to refineries.
EOG is investing in rail — a new crude-by-rail facility in St. James, La. — that is ramping up to handle 50,000 bpd in summer and 70,000 bpd by the end of the year.
The new facility allows EOG to deliver Bakken crude to either St. James or Cushing, Okla. 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 need for rail to move crude from Midcontinent fields will likely persist, even if plans for expanding pipeline links from the Bakken to the Gulf Coast are realized, Papa told a Colorado conference.
He said rail will still be used five years from now to deliver Bakken crude to all three Lower 48 coasts — the Gulf, East and West — but that the current advantage of Louisiana Light Sweet, LLS, crude prices in the Houston market could evaporate within 18 months.
The differential for LLS stood at $21 a barrel over West Texas Intermediate in February.
Papa said there will always be the “advantage of a price lift” somewhere in the United States that will generate a “pretty fat margin.”
However, he said there are no guarantees that the LLS margin will extend into 2014-15, and that perhaps in the future EOG will deliver Bakken crude to other regions anof Polar in McKenzie County, wells will not be brought on stream at the same time. At Smokey — also a 12-well test with tight well spacing on a 1,280-acre unit — drilling and fracking was already under way in 2012.
“So we’re going to see if there is a difference in production as we frack them over time versus fracking them all together,” Peterson said. “So there’s a little bit of science going into this thing, in trying to figure out what we’ve got here.”
He added: “It is important that we do this work in the early stages of our development program in order to gain information to help us best drain the reservoirs.”
Per well cost downKodiak’s well costs in the deepest, most operationally expensive portion of the Bakken have dropped to $10-$10.5 million from $11.5-$12 million per well, the company said.
Kodiak is drilling wells much faster than a year ago due to efficiencies built into the system, Peterson said. A well that once took 35-38 days to drill now takes 20-23 days, with some wells taking less than 20 days to drill.
Crew quality has improved, Peterson said, adding that more wells are being drilled and completed per pad.
Kodiak recently took delivery of a seventh operated drilling rig.
The rig was mobilized to the Smokey project area in McKenzie County, where it will commence drilling a four-well pad, the company said.
Expansion by acquisitionKodiak, which is focused on the Bakken petroleum system of the Williston Basin, is multiplying its acreage and production in the basin under a purchase and sales agreement reached with Liberty Resources, a small private E&P company, also based in Denver, Colo.
Kodiak is paying $660 million in cash for the assets — 5,700 boe equivalent production per day and 42,000 net acres in North Dakota’s Williams and McKenzie counties.
“The proposed acquisition’s characteristics adhere to our stated strategy of identifying and acquiring reduced-risk, contiguous leasehold in our immediate core areas,” Peterson said.l further strengthen our position.”