In a May 3 conference call following the release of first quarter earnings, Continental Resources executives told investors they were planning seven more Three Forks second-bench wells, along with their first third-bench well — all in 2012 and early 2013.
“Our first third-bench well will be drilled in the 1,280-acre Charlotte unit. This well will be … 0.5 miles east of the (2011) Charlotte 2-22 second-bench producer and 660 feet east of the Charlotte 1-22 Middle Bakken producer,” said Jeff Hume, Continental’s president and chief operating officer.
“In addition to this third-bench test, we also plan to drill a first-bench Three Forks well between the 1-22 Middle Bakken well and the 2-22 second Three Forks well,” Hume said.
When finished, he said, Continental’s Charlotte unit in North Dakota’s McKenzie county will be the first 1,280-acre unit in the Williston basin with wells completed in four different members of the Bakken petroleum system.
Starting in mid-2008, Continental was the first company to drill a horizontal well into the first bench, or upper, Three Forks, a variable tight oil reservoir consisting of green and pinkish-tan carbonate mudstone, as well as shale but with no organic content.
The first-bench, or upper Three Forks reservoir, lies about 20 feet below the Lower Bakken shale member, which until recently was where all Three Forks production came from.
Continental has since been joined by Burlington Resources, now part of ConocoPhillips, and Whiting Petroleum, in testing the lower, or second bench, of the Three Forks formation.
In 2011, Oklahoma City-based Continental cut six complete vertical cores of the Three Forks formation, which the company said was 180-270 feet thick under its acreage, over a distance of 115 miles north to south.
Hume told Petroleum News Bakken in a May 15 email that two more such core holes have been taken “thus far in 2012. Two more are planned for this year.”
“All cores taken to date indicate oil saturation between the base of the Lodgepole to the top of the Nisku Anhydrite, which we consider the Bakken system,” Hume wrote.
Similar output to typical first-bench
Hume said Continental was “very pleased” with the performance of its first two second-bench Three Forks wells, the Charlotte 2-22H and the Sunline 11-1, noting the two wells average estimated ultimate recovery, or EUR, would probably be around 650,000 barrels of oil equivalent.
The Charlotte had yielded 64,000 boe since it had come online five and a half months prior; the Sunline had produced 48,000 boe in its first 2.8 months.
“Both wells continue to produce in line with the typical first-bench Three Forks producers,” he said.
More oil than previously thought
Hume said the drilling Continental would be “doing the rest of this year and into 2013” in the second- and third-bench Three Forks would prove or disprove that “there’s interference between those horizons. Right now, we don’t believe there is, but we’re going to do the work, spend the money. … I believe we just have a larger petroleum storage system than we previously thought, and the reserves will increase as we get that data in hand, and that will be later this year.”
In the email to Petroleum News Bakken he said, “We will test the commerciality of each bench and the separation (or interference) between the benches over the next several years.”
Hume did not have a “quantifiable” number on May 3 to go with his prediction, but said the company’s budget was based on the 603,000 boe EUR it had previously set for North Dakota Bakken wells.
“Still, there’s an upside out there and we’re working on that,” he said.
Midnight Run
In his presentation, Hume also talked about a 320-acre development under way for the Middle Bakken and the first bench of the Three Forks.
The Midnight Run project, he said, currently had three Middle Bakken and three Three Forks producing wells in a single 1,280-acre unit.
The wells, which had begun production in the first quarter with average initial outputs of 1,300 boe per day, were 1,320 feet apart in each horizon, with the Middle Bakken wells offset by 660 feet from the centerlines of the Three Forks.
Interference testing was under way, Hume said, the results of which would “help guide future drilling density for the play.”
90% of Bakken good for Eco-Pads
A shift to more ECO-Pad drilling in North Dakota, which was helping Continental reduce drilling cycle times in the Bakken, was a “key trend” Hume advised investors to watch.
In previous presentations company officials had described ECO-Pad as a drilling technique whereby Continental drilled four wells from a single drilling pad.
“The approach allows us to develop two separate formations on two separate spacing units simultaneously, increasing production efficiency. It also allows us to harvest more of a reservoir’s resources while reducing environmental impact on the surface of the land,” Continental said in a posting on its website that was dated February 2012.
“While other companies are using a single-pad technique for extracting natural gas, we are using the technology to drill for oil. We completed our first ECO-Pad project in 2010 in Dunn County, North Dakota from the (first bench, or upper) Three Forks and Middle Bakken formations of the North Dakota Bakken.”
The ECO-Pad technique “provides an estimated 10 percent cost savings on the drilling and completion of each well,” per Continental.
Hume told Petroleum News Bakken that “No ECO-Pads were completed in 1Q12, but several were drilling. Four ECO-Pads were completed in 2010, seven in 2011, and three thus far in 2Q12. There are two in the completion process at this time and six 4-well and two 2-well ECO-Pads drilling.”
He also said, “we expect to have 50 percent of our rig fleet drilling ECO-Pads by year-end 2012 and up to 75 percent by the end of 2013.”
Hanging onto other 10%
In the question and answer session that followed Hume’s May 3 presentation, Noel A. Parks of Ladenburg Thalmann & Co.’s research division, asked him to give listeners a sense of how much of Continental’s acreage in the Bakken was not suitable for ECO-Pad drilling because some of the company’s tracts were “too isolated and so forth.”
Hume predicted “most” of Continental’s acreage would be suitable: “Right now, if I had to make a guess,” he said, “I’d say 90 percent of our acreage would be disposed to ECO-Pad development. And even where we just have a single 1,280 spacing unit, we can do multiple wells from a common pad. So we can probably do three wells in one horizon for a pad.”
What about the 10 percent that wasn’t suitable, would Continental put it for sale, Parks asked.
No, Hume said, the company would likely “go ahead and develop it. … As we learn more and more about these lower benches of the Three Forks, even on that 10 percent we’ll probably be able to do pad drilling on multiple horizons.”
Making it clear that Continental was “very bullish on consolidating acreage in the Bakken,” Hume said in that petroleum system there were “always six or eight packages out there of various sizes to compete for,” and although Continental “obviously can’t buy every one” it evaluated, it was still “always competing” for Bakken acreage.
“We’ve got our cost structure down. We’re probably the lowest-cost operator and best performer up there right now just due to our size and the team we’ve put together,” he said.
A few 40-stage completions
As reported in the May 6 edition of Petroleum News Bakken, Continental predicted a 47-50 percent production growth in 2012, with 107 percent coming from North Dakota alone.
The company’s first-quarter production of 85,526 barrels of oil equivalent per day was 14 percent higher than its fourth-quarter 2011 output of 75,219 boe per day, and 66 percent more than its 51,663 boe a day average in first quarter 2011.
Continental entered May with production in excess of 91,000 boe a day.
But no new rigs would be required to meet the stepped up drilling because the company had reduced its spud-to-spud drilling cycle time for Bakken wells by approximately 30 percent in the last six months, Continental Chairman and Chief Executive Officer Harold Hamm said in a press release in advance of the May 3 conference call.
“Along with good well performance, the two factors driving our results are faster drilling cycle times and our increased working interest ownership in Bakken wells,” he said.
Consequently, Hume was asked May 3 by Hsulin Peng of Robert W. Baird & Co.’s research division, what kind of cost savings had Continental realized from the 30 percent reduction in drilling cycle time.
He said, looking at an average of $20,000 per day rig rate, “by shaving off one week’s time,” the savings was about “$300,000 net per well.”
Strong production from 30-stage completions
Hume was also asked whether the increase in Continental’s production was more about additional wells going online or because of enhanced well performance.
“Well, there’s predominantly more wells coming on production. We are seeing better performance as we’re doing more stages. We’re spending more money on the wells than we did a year ago at this time. And last fall, we shifted from a 24-stage completion to a 30-stage completion. We’re sprinkling in a few 40-stage completions at this time. We are seeing very strong production from the 30-stage wells,” Hume said, predicting an upgrade in the company’s reserves.
He also said as Continental starts doing “more density drilling, we’ll get more effective fracture swarms around the well bores and build better drainage patterns for the well bores. So that’s been the history in resource plays. We feel that we’ll carry on in the Bakken, and that’s a future upside we hope to bring to this play (Three Forks), but we’re not there yet.”
More rigs likely going into 2013
In its May 2 release, Continental said it was increasing its 2012 capital expenditures from $1.75 billion to $2.3 billion, with nearly all of the additional spending going directly to Bakken drilling.
On May 3 Hume said “it’s all entirely” going to Bakken drilling.
Andrew Coleman from the research division of Raymond James & Associates remarked that it looked like Continental’s capex was “pretty front end-loaded.” He asked whether Hume thought spending and activity might pick-up in the second half of 2012, should the company revise upwards some of its EURs.
“Earlier in the year, when we were talking about our capex … we were talking about adding rigs to the Bakken play as we went through the year,” Hume replied.
“We’ve been able — as Harold said earlier — (to get) more completions per rig, and so we’re getting a better capital spend due to that. … So we’ve … already accomplished part of the goal. That being said, we have the personnel put together and the capacity to expand rig count going into 2013 and ’14. And with our inventory and if the commodity prices hold on, I fully expect to continue to expand our activity going forward. Over the next several years, not just the remainder of 2012, but over the next several years, I expect us to continue to grow our (rig) count if the economic environment holds as it is right now,” Hume said.
