The Permian Basin continues as a change leader in the global energy mix, leading North American oil production and forcing OPEC to maintain its production cuts designed to balance the worldwide oil market.
According to the U.S. Energy Information Administration (EIA), oil production in the Permian increased 73,000 bbl/d month over month between February and March. The EIA reported that the Permian produces 3.2 MMbbl/d, which makes it far and away the largest producing onshore oil field in North America.
Scott Sheffield, executive chairman of the board at Pioneer Natural Resources, discussed Permian Basin production and completion trends at the AAPG Global Super Basins Leadership Conference in March in Houston.
Sheffield said the Permian’s rig count had most of its increases in the first six months of 2017, which is a component of the basin’s continued increase in production. Baker Hughes, a GE company (BHGE), stated in its monthly rig count report in May that the Permian reached an all-time high in the number of operating rigs with 463 as of May 11. However, there might be indications rig activity may be beginning to taper off a bit. According to the BHGE rig count report, the Permian Basin has added 63 rigs this year, a drop-off from previous years. During the same time period last year, from Jan. 6, 2017, to May 12, 2017, the rig count grew from 267 to 357, an increase of 90.
“If you look at the month-to-month increase in production, most of the growth in the Permian was over the last several months,” Sheffield said. “It went from 2.1 million barrels per day and finished the year at 2.8 million barrels per day last year. Most people have it growing at about [a rate of] 800,000 barrels per year.”
He said the Permian will steadily increase production by about 19% each year through 2026, based on $55/bbl prices.
“We know the rock is there and the oil is there,” he said.
Enhanced completion designs
Sheffield attributed the production growth in the Permian to improved economics from service cost reductions and enhanced stage spacing designs.
“We’re producing spacing between stages to 15 feet [4.5 m] to 20 feet [6 m], down from 60 feet [18.2 m] to 80 feet [24.3 m],” he said.
Pioneer’s lateral lengths in the Permian have grown from 1,524 m (5,000 ft) and are now averaging 3,048 m (10,000 ft) with some out 6,096 m (20,000 ft), Sheffield said. Enhanced completion designs have been a factor in lowering breakeven costs for the Permian, which Sheffield said is about $19/bbl for Pioneer, including drilling and development costs. The company has seen increased drilling efficiencies recently as well.
“It took us 15 days to drill a vertical well back six, seven, eight years ago,” Sheffield said. “Now it’s taking 15 to 20 days to drill a horizontal well down 10,000 ft and out to 20,000 ft.”
In 2015 Pioneer, which is the largest acreage holder in the Midland Basin, implemented a completion optimization program that combined longer laterals with increased stage lengths, more clusters per stage and higher levels of fluid volumes and proppant concentrations. The company reported in its first-quarter 2018 investor presentation that the objective of the program was to improve well productivity by allowing more rock to be contacted closer to the horizontal wellbore.
By 2016 Pioneer was continuing its efforts to enhance its completion designs with its Version 3.0 completions. Those designs featured proppant concentrations of about 2,000 lb/ft, fluid concentrations of up to 50 bbl/ft, 15-ft cluster spacings and stage spacings down to 30.4 m (100 ft). According to its report, Pioneer placed 47 Version 3.0 wells on production during the first quarter of the year as well as 16 wells on production that utilized even higher intensity completions, which the company refers to as Version 3.0+ wells. The company reported that its Version 3.0+ wells have “significantly outperformed” nearby offset wells with less intense completions.
According to its first-quarter 2018 report, Pioneer expects to place about 45 Version 3.0+ completions online during the first half of the year. The company is planning to appraise three additional Wolfcamp D wells with Version 3.0 completions this year.
Pioneer is forecasting production growth for the year in its Permian Basin operations to increase 19% to 24% compared to its 2017 production rates, with “production currently trending toward the high end of this range,” the company stated in the report.
Addressing what factors have led the Permian Basin to offer the lowest breakevens, Sheffield said the play’s output offers a high percentage of oil, thereby increasing revenues.
“Generally these wells are coming on somewhere between 75% and 85% oil,” he said. “So you’re starting with a much higher revenue per boe.”
Pioneer reported that its first Wolfcamp D wells with the Version 3.0 completions delivered 130-day cumulative production of 26,000 boe with an oil content of 72% during the fourth quarter of 2017.
Sheffield also said lifting the export ban and pad drilling designs, which include increasing the numbers of wells on a pad, also have contributed to low breakevens in the Permian.
In addition, Sheffield touted Pioneer’s success in developing the Jo Mill Spraberry reservoir, which he said the company began developing more than 40 years ago.
“Pioneer is finding tremendous success in the Jo Mill; we’re probably the only operator that is going into the Jo Mill Spraberry,” he said. “We drilled 7,000 vertical wells over the last 40 years … and now we’re making some of our best wells going 10,000 ft with horizontals in the Jo Mill section.”
In a recent report by Wood Mackenzie, the analytics firm predicted Lower 48 crude production growth this year will be approximately 1.1 MMbbl/d, with 80% of that growth attributable to the Permian Basin.
Jonathan Garrett, research director of Lower 48 upstream oil and gas at Wood Mackenzie, said in the report that much of that growth will depend on how quickly and effectively operators develop and deploy new technologies that address key production issues.
“New technologies, such as diverting agents, microfracturing, coil-tipping fracks and digitalization, all have the potential to increase production in the Permian,” he said.
One of the most prevalent risk factors to continued production gains in the Permian and elsewhere in unconventionals is the issue of parent-child well performance, well-on-well performance caused by tighter well spacing.
“Closely spaced child well performance presents not only a risk to the viability of the ongoing drilling recovery but also to the industry’s long-term prospects,” Wood Mackenzie stated in its report. “Virtually every operator believes child well performance is a material issue, but there is no consensus on how to best address it.”
The analytics company said this year will be one of trial and error as a result of the wide range of development techniques and views on optimal spacing operators choose to implement.
Stephen Beck of Stratas Advisors noted in a recent report on Permian Basin production trends that rig counts there could plateau as operators continue to focus on optimizing completions.
“While additional growth in the number of rigs drilling is feasible, incremental growth is more likely as operators shift their attention to optimizing the latest well designs,” Beck said in the report.
Stratas estimated lateral lengths will increase by roughly 25% this year compared to the recent standards averaging just less than 1,828 m (6,000 ft). Using a new 2,133-m (7,000-ft) figure, Stratas estimated drillers will create between 12.1 MMm (40 MMft) and 15.2 MMm (50 MMft) of new lateral footage in the Permian this year.
Permian operator updates
Exxon Mobil reported in its fourth-quarter 2017 investor report that it plans to ramp up its drilling program in the Permian and Bakken from 26 rigs to 36 by the end of the year. The company is producing about 200,000 bbl/d in the Delaware and Midland, a level it expects to increase to nearly 800,000 bbl/d by 2025. The company reported that it is assessing potential additional Permian stacked pay zones while investing $2 billion in infrastructure improvements in the region.
Cimarex reported in its fourth-quarter 2017 investor report it has experienced improved well performance through changes to its completion designs in the Culberson area of the upper Wolfcamp. According to the report, 15 wells with the new fracturing design have averaged 30-day peak IP rates of 2,172 boe/d (52% oil), a 30% increase in first-year cumulative production.
Under its previous completion design, Cimarex had 360-day cumulative production rates of about 500,000 boe/d, the report stated. By implementing its improved completion designs, the company’s rates increased to about 690,000 boe/d.
EOG Resources has cited continued improvements in production rates as a result of the company’s Premium Well program it implemented in 2016. According to its fourth-quarter 2017 investor report, EOG’s Wolfcamp average six-month production on a 2,134-m (7,000-ft) lateral is nearly 1,200 boe/d. The company reported that it is targeting well completion costs this year of $7.4 million, compared to $7.7 million last year in the Wolfcamp.
In addition to its improved well program, EOG has installed infrastructure that includes water sourcing, gathering and recycling capabilities as well as sand rail car unloading facilities.
Meanwhile, Devon Energy’s Anaconda development— the company’s first multizone development in the Delaware Basin—has led to cost savings of $1 million per well compared to traditional pad development activity, the company reported in its fourth-quarter 2017 investor report. Anaconda’s success has encouraged Devon to plan six more multizone developments scheduled for this year. According to the report, about 70% of the company’s capital activity this year will be associated with multizone development projects.
Another key multizone project for Devon is the 11-well Boomslang project in the Thistle area, co-developing the Leonard Shale and the multiple Bone Spring intervals, according to the company’s report.
Devon’s latest Delaware production rate, according to the investor report, is 75 Mboe/d. The company said its production growth in the region was driven by a ramp-up of the Anaconda project and several high-rate wells near the New Mexico/Texas state line.
State line activity was highlighted by six Bone Spring wells that attained 30-day IP rates of 1,750 boe/d at a cost of $5.4 million per well.
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