The News From DUG Permian

Well completions have steadily been getting more efficient, but industry participants think more achievements lie ahead. “There’s a huge upside in driving efficiencies in our industry,” said Dan Themig, president and CEO of Packers Plus Energy Services. He spoke at Hart Energy’s DUG Permian Conference and Exhibition in Fort Worth, Texas, on how to improve well results in a low-cost environment.

A recent study found that more than one-third of stimulated stages in unconventional reservoirs did not contribute to production. Poor cluster efficiency also leaves reserves behind, said Themig, because reservoirs are not homogeneous, and differences in properties along the length of a lateral can influence where fractures initiate and grow.

Replacing stages with complexity is a potential solution, offering better completions for less cost. A technique in this emerging area is rapid execution strategy, which hinges on generating fracture complexity and actually affecting the rock mechanics of the reservoir.

One firm, Painted Pony Petroleum Ltd., has dramatically improved its type curve from 5 billion cubic feet (Bcf) to 13.5 Bcf per well in Canada’s Montney play, partly by using rapid execution. First, the company drills parallel well pairs. It rapidly fractures all the stages in the left-hand lateral, and the well is shut in with no flowback. Then, the completion crew quickly moves to stimulate the right-hand lateral.

The goal is to get the fracks to collide with each other and create a sizeable area of complex fractures between a well pair. The concept can work in both openhole and cased laterals, but observations to date on both types of completions have shown that openhole completions respond particularly well, exhibiting a high number of early-time and lower-intensity fractures, noted Themig.

Operators also seek flawless execution on location. Packers Plus’ new e-PLUS Retina™ monitoring system collects and analyses real-time data using a small device that is easy to set up. It supplies immediate feedback about the job as it is occurring, including detecting such incidents as a ball that fails to launch or a double shift on a stage. The quick feedback allows field operators to swiftly make adjustments on site to ensure each stage is properly treated.

At the recent DUG Permian Conference and Exhibition, executives emphasized how drilling and completion efficiencies and other innovations are preserving economics.

“We have driven our efficiencies up close to 100% on the jobs that we have been on,” said Themig. “I believe that we will be able to determine—in real time, on the fly—when we are getting complex fracture development.”

A third evolving strategy is the drilling of dual and triple-lateral wells. This tactic is well-suited to the Permian Basin, given its multiple horizontal targets, said Themig. “It is possible to design wellbore construction to do downspace drilling from existing wellbores, and this can include dual laterals.”

Painted Pony Petroleum Ltd. has improved its type curve from 5 billion cubic feet (Bcf) to 13.5 Bcf per well in Canada’s Montney play, partly by using rapid execution, involving parallel well pairs.

Currently, operators use single-well pad developments for all the objectives in an area; now they are looking at drilling infield and multilayer wells from a single wellbore.

The potential cost benefit of multiple laterals is clear; the issues have been execution. But that is changing: Themig’s firm has been involved in completing more than 1,000 laterals in dual- and triple-lateral wells. In these projects, a frack string with a bent joint is run into the well. This allows access to the selected lateral. After the first lateral is stimulated, a bridge plug is set above the openhole to prevent balls from transferring over into the second leg.

While these technologies are still being tested and developed, they collectively offer the possibility to deliver the oilfield Holy Grail to completion engineers—better, cheaper wells. “Driving costs down is only part of it; our goal is to move those cumulative curves up as well,” said Themig.

—Peggy Williams

The right acreage and data

Savvy land strategies and data collection also are yielding success in the basin. Laredo Petroleum Inc., a Permian specialist, bought most of its acreage there from 2008 to 2010.

“We were drilling horizontal wells, well before most people even thought that was a value. If you’ve got the right acreage [and] you’ve got stamina [then] you have a chance at really winning,” said Randy Foutch, chairman and CEO. He led the opening keynote presentation on enhancing returns at DUG Permian.

As of March 2015, the company held 179,722 gross (149,141 net) acres and about 4.3 billion barrels (Bbbl) of resource potential on more than 7,700 locations in the Permian.

About 3,200 of its operated horizontal locations in which the company has more than a 90% average working interest are development-ready. “That makes you want to get up early and go to work,” Foutch said. “The contiguous acreage is something that’s pretty important to us, and it has huge advantages, also.”

From the start, Laredo focused on long-term value. It hired quality people, acquired contiguous acreage, collected quality data, maximized net present value (NPV) and kept its options open.

“Buy the best acreage possible. If you don’t have good acreage, nothing else matters,” Foutch said.

“The investments we made in infrastructure a number of years ago are paying off [or] starting to. The investment we made in data collection is starting to pay off. And being an early entry in the play and getting the right acreage is starting to pay off big time for us.”

Laredo’s technical database is integrated with 3-D seismic to allow it to position wells across multiple horizons to maximize value, he said.

“Our view is that the better data you have, the better decisions you make. So we’ve been spending money, time and effort from Day One collecting data,” he said.

Laredo has an extensive whole core database, high-resolution 3-D and lots of production logs, he said. “You’ve got to build [the database] at certain times. You can’t get some data only one time in the history of the well. Once you run casing, you’re limited to some of the logs you can run. Once you’ve had the well on artificial lift for a while, your production logs aren’t as sanitary perhaps in terms of quality of the data. So this database and the contiguous acreage have been very helpful to us.”

The company’s goal is to develop the entire resource and maximize efficiency by drilling stacked laterals on multiwell pads and concentrating facilities along production corridors.

“Our job is to maximize the NPV. That’s difficult to do early on in this type of resource play, but we think we’re headed in the right approach [and applying] the right method,” he said.

The company has achieved average cost savings on a multiwell pad of about $400,000 per well. In 2013, Laredo had 13 horizontal wells on multiwell pads; in 2014 it had 56. It currently has four horizontal wells per multiwell pad.

Capital efficiency gains from drilling longer laterals, cost savings from multiwell pad drilling and additional service cost savings can generate well economics that rival the returns from a higher oil price environment, he said.

Centralization of infrastructure saves about $1.2 million per well, Foutch said. A four-well completion requires 1 million barrels (MMbbl) of water in two weeks and takeaway capacity of about 82,500 barrels of oil equivalent (boe) per month, rising to about 93,000 bbl of water per month during peak production.

Additionally, production corridors help efficient development of the entire resource, Foutch said.

“We have four corridors in various stages of development. We will need others as we finish drilling the blocked-up acreage. [Also,] 50% of our crude oil today never sees a truck; it goes straight from the wellhead through pipe, all the way to where we sell it,” he said.

Laredo is a 49% owner in the Medallion Pipeline, which offers access to pipeline connections in in Midland, Colorado City, Cushing, Oklahoma, or the Gulf Coast.

—Ariana Benavidez

Verticals work, too

Another Permian operator, privately owned RKI Exploration & Production LLC, explained how it is positioned to ride out the downturn. Like Laredo, the Oklahoma City-based E&P has a contiguous acreage position in the basin with 90,000 acres mostly in Eddy County, New Mexico, and Loving and Reeves counties, Texas.

RKI’s acreage offers liquids-rich, stacked-pay opportunities, Ronnie K. Irani, the company’s foun­der, president and CEO, told attendees at DUG Permian.

“We’ve stayed intentionally under the radar and just gone about our business, which is about drilling and finding oil and gas reserves,” Irani said. He reminded the audience not to forget the benefits of vertical wells.

“We’ve drilled 118 vertical Delaware [Basin] wells,” Irani said. “I’ll submit to you that the vertical Delaware economics are as good as anything you’ll hear today [at the conference].”

RKI is active in four plays in the Permian, including its current favorite, the Wolfcamp. The company has also drilled the Bone Spring, Avalon Shale and in the Delaware Basin.

“In the Delaware, you drill vertical wells,” he said. “It’s a very thick section, it’s multilayered, and vertical wells work best at this point. We drill them on 40-acre spacing. It’s oily and great economics, so we’ll continue to do that.”

RKI’s operations are focused on the Powder River Basin in Wyoming and in the Permian. Before oil prices crashed, the company operated 11 rigs—five in the Powder and six in the Permian. Now it is down to one and three, respectively.

“We’re looking at adding one in each of the basins in the next month or so and by year-end. We plan to get up to six in the Delaware and at least three in the Powder. We feel like it’s picking back up again.”

Laredo Petroleum has achieved average cost savings on a multiwell pad of about $400,000 per well in the Permian.

RKI relies on oil and liquids for between 70% and 75% of its production in both basins.

In addition to lower service costs, Irani said the combination of pad-drilling efficiencies, drilling optimization and zipper fracks has shaved Wolfcamp well costs from $9.7 million.

“We’re looking at a $6.8 million Wolfcamp well,” he said. “Under current pricing, it would give us a 40% rate of return. If you assume a $65 or $70 oil price, we’re looking at upward of 55% to 60% rate of return.”

For a small company, RKI nevertheless ranks relatively high among Delaware Basin producers in rig count and production, at 30,000 boe/d.

RKI Exploration & Production LLC emphasized the rates of return still achievable in the Delaware Basin’s horizontal Upper Wolfcamp, due to reduced well costs.

—Scott Weeden

Reloaded in the Permian

Operator Apache Corp. also discussed its strategy in the Permian at the conference. It is reloaded and ready for what lies ahead, said Faron Thibodeaux, vice president of the company’s Permian Basin region.

The Houston company projects its 2015 capex in North America will be around $2.1- to $2.3 billion with “a lion’s share” for the Permian Basin, Thibodeaux said.

The company, which started the year out under new leadership, is the second-largest producer in the Permian and the third-largest leaseholder.

In January 2015, John Christmann succeeded G. Steven Farris as president and CEO. Christmann, who has been with Apache for 18 years, established the company’s Permian Basin-Midland office.

He helped increase production in the Basin to an average of 159,000 boe/d in 2014, from about 52,000 boe/d in 2010 when the company entered the play.

“John is taking the bull by the horns and we’re fully behind him and aligned to support him,” Thibodeaux said.

The company’s portfolio also was transformed over the past five years to a focus on North American unconventionals.

About 64% of the company’s production in first-quarter 2015 was from its North American onshore operations, Thibodeaux said. In contrast, in 2009, two-thirds of the company’s production was from international and Gulf of Mexico operations, while only one-third was from North American onshore.

In 2015, the company will allocate 85% of its capital to nine primary plays in North America—three of which are in the Permian Basin. “We are moving to the cores of those areas that add the most value for us,” Thibodeaux said.

The company plans to run four to five rigs in the Delaware Basin, two to four rigs in the Southern Midland Basin and two to three rigs in the Central Basin Platform/Northwest Self. It currently has a backlog of wells in the Delaware Basin, which it hopes to complete later this year.

“Once cash flows tell us it’s time to ramp up, we will ramp up,” he said. “But we will do it very diligently.”

Data is driving development. The company has a large 3-D seismic inventory in the Permian Basin covering 12,500 square miles, which is about 8 million acres. And it will continue gathering high-quality data while costs remain low, he said.

In 2015, the company will reprocess about 2,600 square miles of data in the basin and acquire about 500 square miles.

Apache also has newbuild rig commitments in the Permian Basin and plans to proceed as planned, despite the oil price downturn. Through technology gains, the newbuild rigs will pay for themselves, he said.

Thibodeaux took over the Permian region in July 2014, around the time crude oil hit its peak.

The company reacted quickly when prices began to drop, he said, cutting capex by more than 60% and its North American rig count down to some 14 from 90 rigs in the summer of 2014.

“That’s what a ramp down looks like in the 80-to-90-rig range,” he said. “If you were a snow skier, I think you would call that slope a black—and it’s felt like one.”

—Emily Moser

Northern Delaware Basin core

Matthew Hairford, president of Matador Resources, led the DUG Permian session on the northern Delaware Basin, where stacked pay opportunities have helped operators survive in the downturn.

Like most companies in the industry, Matador has cut its capex significantly for 2015. In 2014, its capex spending was $610 million. For 2015, that’s been pared to $350 million. Still, production has grown.

“In 2012, we had 1.2 million barrels of oil for the year, and in 2015 we’re going to have 4.2 million, so a lot of good growth there; we’re up 27% with the oil [production], and natural gas production is up 63%,” Hairford said.

Matador has completed its Eagle Ford drilling operations for 2015, and more than 95% of the company’s Eagle Ford acreage is either HBP or not burdened by lease expirations until 2016 or later. “We’ve learned a lot about shales [from the Eagle Ford] that we’re going to bring to the Permian,” he said.

Apache is investing about 85% of its drilling capital in nine primary plays.

Most of the company’s Permian acreage is in the Delaware, where it has 152,370 gross (85,375 net) acres in southeast New Mexico and West Texas.

Hairford reviewed the recent test results of the company’s horizontal wells in the Permian. Of note, Matador’s Dorothy White #1H well produced 358 Mboe, 1,100 Mcf/d of natural gas and earned a 1,050 Mboe EUR in its first 15.5 months.

The company’s Ranger State well, which has been on production for 17 months, has produced 197 Mboe, 200 Mcf/d of natural gas and has an EUR of 650 Mboe.

“Most of the operators in the area are focusing on Second Bone Spring, and we think that is a great target as well. The technical team looked at the Wolfcamp B and said ‘this looks good; let’s try one here.’ So we did that, and that’s our Rustler Breaks well. It’s been on [production] about a year. It’s made 170,000 boe and it’s online to be about a 700,000 boe EUR on that well.”

Regarding technology advances, Hairford said, “One of the things we did that I think is unique to the Permian but not unique to other areas is setting up these rigs for simultaneous operations. What we’ve done is basically rotate the v-door and the catwalk 90 degrees. We can move a frack crew in and start fracking wells while we’re drilling other wells.

“The reason that is significant here is you can’t do that in the Eagle Ford and other basins, where you’re drilling the wells at the same interval.”

Moreover, new rig improvements include the 7,500-psi pressure rating system, with an estimated reduction in drilling time of 15% to 20% in the lateral on Wolfcamp wells. “The 7,500-psi circulating system allows us to run a much more robust downhole drilling system so we’re able to run bigger motors, get a higher penetration rate and knock these days off the well,” he said.

—Ariana Benvavidez

Deciphering spacing

Well spacing in the Permian can be a sensitive issue as operators determine how close is too close. “I’m going to talk about something that most CEOs probably don’t want to talk about, and that is why I think the wells we are drilling in the Wolfcamp and the Spraberry out in the Midland Basin ultimately will probably average a little bit less per well than what people are saying they are right now,” said Steve Gray, CEO and director of RSP Permian. He spoke on a panel on the Midland Basin at DUG Permian.

Still, the oil-in-place resources are massive in the basin, he said. “If you look at a type log in the middle of the basin, you can see in addition to the five zones that we’ve been producing there are probably four or five others that have potential and have been tested by other operators or are carried in the inventory of other companies.

“You’ve got a total section that’s probably 3,000 feet or 4,000 feet thick (that’s pay), and when you compare that to other resource plays in the U.S., it just dwarfs most of those other plays,” he said.

RSP Permian has spent the past couple of years in delineation mode. Now it is moving into development.

Matador Resources Co. president Matthew Hairford said capex is down more than 40% for the Permian but its production is up.

“It’s a complex sort of three-dimensional game of chess deciding how to develop these reservoirs,” he said.

“The first thing we did is we used log core data to try to come up with what we think the oil in place is, how big the target is, and then obviously the next step was to go drill the delineation wells and figure out what the wells are capable of making [and] work on the completion technology,” he said.

Next, the company completed some microseismic surveys to try to determine how big an area it was draining. It also did spacing pilots and put some wells in side by side to see how they would communicate with each other and react.

“[We wanted to] see if we can come up with what we believe is the most efficient way to develop the reservoir, and when I say most efficient, what I’m talking about is how do I maximize the net present value of this particular lease or this block. I’m not so much interested in how much oil each individual well is going to make as I am [with] how do I get the maximum value out of the resource,” he said.

Spacing pilots in low permeability reservoirs will take a long time to resolve, Gray said.

Currently, RSP is trying to determine how wells are going to produce if the wells are drilled closer together. “This is what nobody wants to talk about,” Gray said. “[But] this is what we all want to figure out in this industry.”

Gray said if an operator drills four wells across a section that is going to make 900 Mboe, the operator is only going to recover 2% of the oil in place. If the operator sets five wells at 3 MMbbl across a section, the operator is going to get about 2.5% of the oil in place. If an operator expands from five wells to 15 wells across a section, results won’t go from 3 MMbbl to 9 MMbbl; instead, the operator will go from 3 MMbbl to perhaps 7 MMbbl, “because each subsequent well means you’re going to get a little less per well,” he said.

“But at the end of the day, we’re still arguing about less than 10% of the oil in place, so I think with changes in technology and completion design, maybe that whole equation changes,” Gray continued. “I’d love if I could tell you guys I’m drilling million-barrel wells, but my guess is when we all go to full-scale development, million-barrel wells are going to be rare, and that’s OK with me because I’d rather drill more 800,000-barrel wells than a few million-barrel wells.”

—Ariana Benavidez

Big data’s might

Given the amount of seismic shot and number of wells drilled since the mid-1950s, the oil and gas industry has amassed massive amounts of data. Long before the concept of “big data” was popular, the E&P industry was searching for ways to tap into that data resource.

Alan Lindsey, founder and CEO, PetroDE, speaks during a session at DUG Permian 2015.

“Fundamentally, big data is about transforming data from a cost into a revenue-generating asset,” said Luther Birdzell, CEO, OAG Analytics. “It can be measured as incremental barrels of oil per dollar deployed. I think big data would be broadly defined as data stored for data requirements that exceeded commercially available technology.”

Birdzell participated in a roundtable on “Big Data Solutions” at DUG Permian along with Ben Shattuck, upstream analyst, Wood Mackenzie; Alan Lindsey, founder and CEO, PetroDE; and James Yockey, president, Oseberg.

Unconventional development is much more complex than conventional development. Additionally, there is much more 3-D and 4-D seismic and microseismic technology data. Computing capacity doubles every two years, adding to the complexity, Birdzell explained. “The industry can benefit most quickly and with the greatest magnitude by approaching this problem from the place of maximizing value to the user by minimizing complexity.”

Shattuck said his company “fundamentally changed the way we look at things like forecasting. It is really due to the advent of big data. How do you take 4 million wells and separate the noise and distraction from what really matters and roll that up into a meaningful industry-level view?

“It is wrapping your mind around what that dataset means, what are the components of that dataset, and understanding—particularly as we roll this out to people who are not very technically minded—what are the capabilities and just as importantly the limitations of that dataset,” he said.

With all of the microseismic, geochemical, geomechanical and production information coming out of the wellbore, there is increased focus on extracting maximum value. Most companies take the information on a well-by-well basis and analyze it, put it under a lot of intense scrutiny and then put it on a shelf, Lindsey said.

“What is available now through the Cloud and data technologies is the ability to keep that data alive and on low-cost systems for instant access. Our industry is always worrying about how to optimize these completions, and someone will come up with a new technique. What you need to do essentially is reprocess all that old data to understand what it means,” he continued.

“The ultimate is to take us from these expensive well-spacing tests where we’re drilling physical wells to determining that spacing from our microseismic, geochemical and geomechanical measurements, so we can get very close to the correct answer right out of the starting gate,” he said. “That will end up saving you millions of dollars.”

Yockey noted that at a conference he attended in Houston in mid-May, one of the speakers, a managing director and head of the Houston office for McKinsey & Co., said one of its recent studies identified data and data analytics as the fastest-growing technology segment in the industry, with the highest margins.

The data available to oil and gas companies isn’t limited to private datasets. Information is available from public and regulatory sources, so the next step for energy firms is to learn how to aggregate and analyze disparate data to generate an actionable business concept.

“Frankly, it is the integration of those pieces that brings a lot of added value.”

As Birdzell explained, “We’re able to materially reduce the uncertainty of key reservoir and completion practices using advanced statistical methods from public data. We are able to do even more with proprietary data.”

As an example of public data’s potential, Yockey referred to Continental Resources’ South Central Oklahoma Oil Play (Scoop), which the company announced in September 2014 as its next big play.

“What we saw at Oseberg in September 2013 was that the Springer would be its next big play, a year ahead of Continental’s big announcement. You could identify this was a new formation that Continental was going to be talking about by mining the details of the formation-specific IPs [initial production rates] that Continental and other operators were releasing through filings with the Oklahoma Corporation Commission,” Yockey said.

“You could have leveraged a bunch of other data like spacing and increased density from filings to not just have your attention drawn to the Springer, but also delineating what the fairway was and Continental’s, Marathon’s and Newfield’s net positions in the play months before this announcement. That’s worth a lot to geologists, engineers and business executives in the E&P industry.”

—Scott Weeden