Since acquiring its South Antelope acreage in eastern McKenzie County last year, QEP Energy is finding the property to be every bit as productive as anticipated when the acquisition was announced. When the Denver-based independent announced the acquisition in August of 2012, it reported an average estimated ultimate recovery, EUR, of more than 1 million barrels of oil equivalent for Bakken wells on the property. Second-quarter production results are suggesting that million-plus barrel EUR may not be far off the mark.
Prior to the transaction, the former operator of the South Antelope property, Louisiana-based Helis Oil and Gas, had drilled only one well per spacing unit to hold the leases, all Three Forks wells. In June, QEP tested its first two company-operated middle Bakken wells in the South Antelope area, and as Petroleum News Bakken reported, those wells came in with an average 24-hour initial production, IP, of 4,174 boepd.
In an Aug. 1 conference call, QEP Chairman, Chief Executive Officer and President Charles Stanley spoke of the importance of the South Antelope middle Bakken results. “These wells were important in that the previous owner had concentrated their development activity drilling one Three Forks well per spacing unit in order to save all the leases on the property,” Stanley said. “We knew the Bakken was present, we’ve seen it on logs, we had core through it. But we didn’t have a modern, state-of-the-art long-lateral Bakken completion on our acreage. Our first two QEP-operated Bakken completions, with post-processing 24-hour IPs of over 4,500 boe per day, confirm the middle Bakken is every bit as good and perhaps even better than we had modeled in our acquisition evaluation.” Stanley added that the results are “a reflection and confirmation of what we recognized and analyzed when we made the South Antelope acquisition last year.”
Four middle Bakken wells
Through the second quarter, QEP completed a total of four middle Bakken and two Three Forks wells in the South Antelope area, all on a single pad in the Grail field. Those include some of the company’s first long-lateral wells in the South Antelope area extended as far as 12,500 feet. Stanley says these six wells had a collective 30-day average production of approximately 1,300 boepd which continues to meet or even exceed the company’s forecast.
“It’s good rock, it’s overpressured. The quality of the production performance is directly related to that rock quality in both the middle Bakken but also in the Three Forks. Both reservoirs put up some of the best well results in the basin.”
QEP’s current well density in the Antelope area is based on the model of drilling four Bakken and four first bench Three Forks wells in each 1,280-acre unit in the area. However, Stanley said QEP is evaluating the potential to increase well density in the area, both through reservoir engineering analyses as well as some pilot testing. Additionally, QEP is evaluating other potential reservoirs in the sequence. That work, Stanley said, has the potential to materially impact the South Antelope inventory, “both in terms of infill and with respect to additional reservoirs.”
Second-quarter production and operations
QEP’s second-quarter Bakken/Three Forks production averaged 20,400 barrels of equivalent per day, a nearly 17 percent increase over the average second quarter production of 17,000 boepd, and up 11 percent from the 18,348 boepd produced in the fourth quarter of 2012. The decline in production between the fourth quarter of 2012 and the first quarter of 2013 was due to a transition to pad drilling.
In all, QEP completed and brought on production six wells in the South Antelope area and nine in the company’s Fort Berthold area. Five of the Fort Berthold completions were on company’s Independence pad located in the Heart Butte field on the south side of Lake Sakakawea in far northeast Dunn County. The other four were on a pad located about four miles west of the Independence pad, also in the Heart Butte field on the south side of the lake.
Three of the new wells on the Independence pad are middle Bakken and the other two are completed in the Three Forks. Collectively the five wells had an average 24-hour IP of just over 2,100 boepd. The four wells on the other Heart Butte pad, two Bakken and two Three Forks, had a combined average 24-hour IP of over 3,000 boepd according to Stanley.
Eight rigs operating
QEP currently has six drill rigs operating in the South Antelope area and two in the Fort Berthold area. Earlier in the year, the company had five rigs drilling in the South Antelope area and three in the Fort Berthold area, but due to challenges with pad construction in the Fort Berthold area as a result of wet spring conditions, the company moved one rig from the Fort Berthold to the Antelope area.
QEP also participated in a number of non-operated wells in the second quarter, including a 6 percent average working interest in 18 wells that were brought on production in the quarter. QEP also has a 3 percent average working interest in 10 non-operated wells that were being drilled at the end of the second quarter, and a 4 percent average working interest in 28 other non-operated wells that were waiting on completion.
While QEP has had a number of drill rigs operating in the first half of the year, Stanley said drilling activity has not boosted production volumes because the rigs are simply sitting on pads drilling multiple wells. He said the company saw a slight production increase in the second quarter, but the full-year 2013 production will be backend loaded with non-linear production growth forecasted at 18 percent in the third quarter and 31 percent in the fourth.
In terms of crude oil alone, QEP’s oil production was up 12 percent over the first quarter, and up 82 percent from the second quarter of 2012. With the shift to pad-base development in the Williston Basin, Stanley believes the company is on track to reach at least a 70 percent year-over-year increase in crude oil production in 2013.
Managing drilling, completions and costs
QEP is seeing its transition to pad drilling in the Williston Basin begin to pay off. “Pad drilling is helping us drive down well cost by reducing the time and associated cost of rig moves, and mobilization and demobilization costs associated with completion crews and equipment,” Stanley said. “The pad development will also enable us to share some production facilities in gathering lines on the properties.”
Stanley said QEP continues to make good progress on well costs, and is targeting a $10 million or lower gross completed well cost by year end. However, Stanley noted that costs in the Fort Berthold area are higher than in the South Antelope area because of the acreage configuration under Lake Sakakawea. On average, those wells have longer laterals than the South Antelope wells, and Stanley expects the Fort Berthold wells costs to remain higher than the South Antelope costs.
However, pad drilling is not without its problems, and with the transition to pad drilling, according to Stanley, QEP is not able to complete any of the wells on the multi-well pads until all wells are drilled and cased and the rig moved off the pad. This a process, he said, can take four to five months, and that delay adds some “volatility” to the company’s production growth profile.
In response, QEP has been managing the arrival time of rigs on new pads in order to stagger the work on the new multi-well pads. However, Stanley does not believe that the volatility will affect the company’s production growth. “So while there will be some volatility in the production growth going forward, we remain on track to grow crude oil to at least 70 percent in 2013.”
Fracking experiments
QEP is also experimenting with hydraulic fracturing methods and testing various proppants and proppant loads in its South Antelope wells, although thus far the company has not seen any noticeable results.
Stanley said QEP has “a good family of wells in the Three Forks” because the previous operator designed completions with cemented liner and plug-and-perf fracks in its Three Forks wells that can be used to compare proppant performance.
In contrast, QEP is using a sliding sleeve frack technique, averaging approximately 30 frack stages per well on its Three Forks wells. Those wells were drilled very near the Three Forks wells the former operator drilled and the fracks were of similar size. However, Stanley said thus far QEP has not seen any “material difference” in results from the Three forks wells fracked by the previous operator and QEP fracked wells.
The former operator used 100 percent ceramic proppant, while QEP has shifted to hybrid proppant consisting of primarily sand but with a “tail-in” of either ceramic proppant or resin-coated sand. In addition, QEP has increased proppant loads from between 2 million and 2.5 million pounds to as high as 5 million pounds in an attempt to find the “point of diminishing returns.” But here too, QEP has not seen any notable performance difference.
“So it’s been a great natural laboratory to compare early well performance and longer-term well performance, and frankly, we struggle to see any significant difference,” Stanley said. “Now, that doesn’t mean that in certain parts of the basin, where rock quality may not be as good, where geology is different, that there may be a material difference between sliding sleeve and plug-and-perf cemented liner completions. We just don’t see it in the area where we’re operating.”
Be careful with 24-hour IPs
North Dakota requires reporting of initial 24-hour production data, and while that metric is commonly used to evaluate and compare wells, Stanley said QEP looks more at 30-, 60-, 90- and 120-day performance rather than initial 24-hour IP rates. This primary reason is the potential flowback problems that can occur in the first 24 hours of production. He said QEP is struggling internally with maximizing the first 24-hour production rate versus the risk of flowing back a portion of the proppant placed in the fractures.
Based on the company’s experience in the plays like Haynesville, Stanley said QEP believes it may be “advisable” not to get too aggressive on flowback on the South Antelope wells. “So as we go forward, we may, in fact, choke back on these wells a little bit … for initial flowback to avoid any long-term damage to the reservoir.”
Citing a plot of IP versus EUR with an R-squared of 0.3, Stanley said that as the cluster in the plot tightens, at 90 days there is a 75 to 80 percent correlation coefficient. “So I think it’s very dangerous to just look at IPs.”
Transition to liquids
Historically, QEP has predominantly been a natural gas producer, but in 2012 the company began an effort to get more liquids into its overall production mix. In 2011, natural gas accounted for 86 percent of the company’s product mix while oil and natural gas liquids equivalents accounted for only 8 percent and 6 percent, respectively. In 2012, oil equivalent increased to 12 percent of the product mix and NGL equivalents to 10 percent.
The company set a 2013 target of 21 percent oil, 9 percent NGLs and 70 percent gas. Second-quarter production results indicate the company is close to achieving that goal with crude oil representing 18 percent of the company’s product mix and NGLs representing 9 percent for a combined total of 27 percent, bringing gas down to 73 percent of the product mix.
In addition to the Williston Basin, QEP has operations in the Pinedale Anticline, the Uinta Basin in Wyoming and Utah, as well as in the Granite Wash, Haynesville, Woodford Cana, Marmaton and Tonkawa plays in Texas, Oklahoma and Louisiana.
On a billion cubic feet equivalent, bcfe, of natural gas basis, QEP’s second-quarter 2013 total production was 77.9 bcfe. The Williston Basin accounted for 11.1 bcfe of that total output and was a 226 percent increase over the 3.4 bcfe produced in the basin in the same quarter of 2012. Overall, the company’s second-quarter 77.9 bcfe output was a 2 percent decrease over the same quarter of 2012, but for the first six months of 2012, the company’s output was 155.9 bcfe, an increase of 1 percent over the first six months of 2012.
