Imagine for a moment this scenario. It is 2020, and WTI has been under $60/barrel since 2015. How active are the oilfields in the Big 3 US Oil Basins (Permian, Eagle Ford, Bakken)? What’s the North American onshore rig count, and how much frac horsepower is employed? Most important of all, where is US oil production and is it falling?
Determining the answers requires solving a complex equation with hundreds of variables and much uncertainty. But there is one key factor that is more important than the rest. And that key factor is the cost per boe for US producers and how low it can go.
When discussing the future of tight oil production and its relatively high cost vs. conventional development, it is important to remember that large scale tight oil production is only about 6 years old. It is still early days for the practice, and while unconventional oil will always be capital intensive, advances in technology and methodology will continue to drive the cost per boe extracted lower over time. Driving down the cost of unconventional barrels is mission critical for US producers if oil prices do end up staying lower for longer.
In this post, we explore the rise of a recent trend, the superfrac, with input from two of Cameron’s onshore experts: Thomas Roesner and Craig Young. We recently sat down with the two Cameron experts to talk about how superfracs improve well economics, how the practice is spreading, and what the trend means for completion equipment.
Could superfracs save US tight oil in a lower for longer scenario? The short answer is no, not single-handedly, but superfracs are an example of the kind of progressive experimentation that will be necessary for US producers to survive a protracted downturn. And the new approaches companies nurture during the downturn will only enhance the good fortune any recovery scenario brings.
What Is A Superfrac?
The term superfrac has become a buzzword over the past year or so, but the trend has been in the making for several years as proppant volumes have grown. “Superfracs” are hydraulic fracturing stimulation jobs that use two to three times as much sand as “typical” unconventional wells. The term superfrac is used to describe an inflection point in the evolution of downhole intensity.
Defining exactly what makes a completion a superfrac varies, but Craig Young thinks of it in terms of sand volume per foot of wellbore. “It’s kind of a blurry line,” Craig Young says. “The definition is pretty subjective, but most people feel comfortable identifying superfracs as jobs with sand concentrations in the 2,000-4,000 pound per foot range,” Young says.
So superfraced wells can take as much as 10-15 million pounds of sand each. That’s 2 or 3 times as much as the more standard 4-5mm pounds of sand used per well.
In a report this summer, IHS said they distinguish superfracs at a threshold of 1,700 lbs./ft and 900 lbs./ft in the Eagle Ford and Bakken, respectively, based on overall proppant activity in each play, with some companies using volumes as high as 3,000 lbs per foot or more.
Source: IHS Energy
EOG CEO Bill Thomas has led the superfrac charge, leveraging his own sand mine and transloading facilities to complete over 700 wells with the method. He uses the term to describe sand concentrations up into the 4,000 pounds per foot range. EOG has been running extra large sand volumes for several years, and others are starting to follow as falling onshore activity frees up resources to handle the large sand volumes needed.
Frac Sand. Image Credit: Hi-Crush
In late-October, Hi-Crush Partners, a leading sand supplier, said that the sand intensity trend continues to build with superfrac volumes rising. And more E&Ps are experimenting with extra large sand volumes. For example, Whiting confirmed in late-October that they are testing completions in excess of 7mm pounds of sand per well.
Superfracs do have some limitations. Where operators are seeing the most success is in the slickwater environment, Young says. “If you get out of that slickwater environment, that changes your frac structure and the way your frac is placed in the formation.”
Superfracs Vs. Low Oil Prices
What do depressed oil prices mean for superfracs? Cameron’s Thomas Roesner says lower oil prices mean more demand for superfracs not less. “Low oil prices enable operators to buy more proppant because prices have dropped,” Roesner says. “Upgrading to a superfrac isn’t going to increase the expense now like it would have nine months ago. In today’s low cost environment, the appetite to experiment will increase.”
We have heard from operators who say superfracs today can cost less than standard fracs did a year ago because of widespread deflation.
The added sand volumes (and resulting transport and fracturing complexity), mean superfracs do cost 10-25% above the market price of traditional completion jobs. This added cost has been a sticking point for some operators. However, the operators willing to experiment often find that they can lower breakeven prices by as much as 20-25% by making more productive wells. A nice return on the up front investment is the result.
Frac Sand Facility. Image Credit: US Silica
Hi-Crush Partners is working with its sand customers to lower all-in pricing at the wellhead through better origin/destination matching, increasing use of unit trains, and more in-basin services. The sand supplier sees pricing pressure on frac sand continuing into 2016, and a superfrac next year will cost even less than it does today.
Roesner sees growing adoption of the superfrac by operators in this environment. “We’ve seen estimates that as much as 20-25% of the incremental wells being completed in the Eagle Ford and Bakken are superfracs,” he says.
Superfrac Implications For Pressure Pumping Equipment
So a superfrac’s downhole implication is more sand per foot, and the production result looks like more productive wells at a lower average cost per boe. But what are the surface implications for completions equipment from the superfrac trend?
When it comes to the frac spread array, there is no visible change. But the equipment is pumping longer, it is pumping triple the debris, and many more sand trucks are involved. This has several implications. First, superfracing is accelerating the technological obsolescence of traditional frac iron. Second, the sustained use of pressure-pumping equipment at the high performance thresholds required means more wear and tear on frac service equipment. In fact, there has been talk in the industry of frac service companies moving to a pricing model based on sand concentration.
Cameron operates the world’s largest rental fleet of frac equipment, so Thomas Roesner and Craig Young have been on the front-line watching equipment needs change as the superfrac trend evolves. We talked to them about the two big equipment challenges with superfracing.
Superfracs Highlight A Growing Need For New Solutions
Frac equipment has been tested in recent years as operators push lateral lengths, increase the number of frac stages, and drill wells more closely together. Now, superfracs are taking the volume of proppant pumped to all time highs.
The conventional wisdom is to pump more fluid through more lines, but this approach adds to an already tangled maze of lines on the well pad. It also increases the risk that a bad connection will cause delays (or worse) on the job.
Roesner says superfracs are accelerating the technological obsolescence of conventional frac iron. “How the industry uses conventional pipe is constraining operators and pressure pumpers. You need a modern frac fluid delivery network, like Cameron’s patented Monoline. It’s more robust, and it delivers higher concentrations of proppant more effectively.” Cameron’s patented Monoline™ Frac Fluid Delivery System (FFDS) simplifies frac iron and reduces potential leak paths by using a single line to replace up to four separate flowlines to the frac tree in conventional systems.
Image Credit: Cameron
The single line is comprised of a large inner diameter bore capable of accommodating superfrac fluid volumes. Bolted connections promote a higher level of system integrity and safety. Patented swivel flanges allow the full range of motion needed to align the frac tree and frac manifold, while eliminating mismatch potential, simplifying the rig-up procedure, and improving reliability. The time savings from the install alone can total up to four man-days of work, not to mention the reduced likelihood of NPT resulting from the frequent connection failure of conventional frac iron.
Video Credit: Cameron
Roesner says Monoline delivers the change the industry needs to successfully execute superfracs on a larger scale. “The concept of a frac factory to deliver high volume proppant packs is something we market the Monoline Frac Fluid Delivery System for,” he says. “Efficiency is king, and we provide effective technology to drive operator efficiency.”
Cameron’s Monoline system is a good example of the kind of technological advancement the industry must embrace in order to make US tight oil plays work at lower oil prices.
Superfracs And Rising Wear And Tear On Equipment
In addition to catalyzing change in frac iron needs, superfracs have an unwanted side effect – more wear and tear on equipment. From the pump internals to the missile trailer and across the fluid delivery network, superfracs demand more from the equipment. “As you start increasing the amount of sand, all of those components naturally begin to experience reduced useful life,” Roesner says.
Pressure pumpers are increasing their frac iron replacement rates as a result. Part of this is due to the reduction in service life. Because of larger loads, there is less time to pause for checks and maintenance. Over time, increased downhole intensity will lift the baseline of replacement orders for pumps, manifolds, valves etc. This added capital cost is something pressure pumpers will try to pass on to the operators benefiting from the superfrac’s effectiveness.
With as much as 10mm frac horsepower on the sidelines due to the downturn, pressure pumpers are cannibalizing idle components to feed the replacement needs of active spreads. But cannibalization is only a stop-gap measure in the downturn, and as spares run low, replacement component orders will pick up.
In any recovery scenario, the strenuous demands of superfrac coupled with delayed R&M spending will drive a surging backlog of orders for pump components, missile trailers, and frac iron. Well capitalized pumpers would be well served to stay ahead of this trend.
Execution Eats Strategy For Breakfast
When it comes to superfracs, operators are likely to spend most of their time thinking about downhole optimization. Pounds of sand per foot, well location and spacing, and added cost vs. productivity gains are top of mind for E&Ps. This is logical because it is the effectiveness of the frac that pays for the well, not the efficiency of the completion.
But as superfrac adoption rises in the new low oil price paradigm, operators must re-evaluate the surface requirements needed to deliver a successful completion. And pressure pumpers must pursue innovative solutions and find ways to combat the new stresses placed on their equipment.
The surface equipment is as important as what goes downhole, for one poor connection bombarded with thicker frac fluid at 15k psi can compromise the entire frac operation. Thomas Roesner put it best: “execution eats strategy for breakfast.”
Superfrac Sidebar: Addressing The Critics
The critics have several knocks on the superfrac. The debate continues, as the practice is still relatively new, but the data available to date supports the practice as value creative. We discuss two primary criticisms of the practice below:
Criticism 1 – Superfracs just accelerate production, so the decline rate will be higher for superfrac’ed wells and recoverable reserves won’t change. Although industry only has about 2 years of production history from just one operator, the average decline rates for superfracs vs. standard fracs doesn’t show any meaningful difference in decline rates. At this point, it appears that superfracs may actually create additional recoverable reserves rather than simply pull forward production. IHS examined the well stats for EOG, finding that super and standard fracs are declining at about the same pace over the first 24 months in the Eagle Ford and in the Bakken. Decline rates seem more determined by the play than the super vs. standard frac distinction.
Source: IHS Energy
Criticism 2 – Interference from more intense fractures may limit infill drilling opportunities. The idea is that well spacing could be impacted because superfracs impact the reservoir beyond a standard frac. Craig Young says operators will argue that well spacing can still be tight because sand isn’t transporting any further from the wellbore vs. a normal frac. In other words, the increased sand is simply increasing complexity close to the well bore, meaning no change to the potential well set, just better wells because of the increased reservoir contact near the well bore. Time will tell.
Source: Aurora O&G
Meet The Cameron Experts. We’d like to thank the Cameron team that contributed to this post, including Lucile Turpin, who facilitated the discussion and provided valuable insight in the creation of this post.
Thomas Roesner Mr. Roesner possesses over 20 years of experience and knowledge in the oil and gas industry. He has held positions in operations, engineering, sales and marketing, product line management, and business development with Schlumberger, Weatherford, National Oilwell Varco, and GE Oil & Gas. Currently, Thomas serves as the Global Business Development Manager for CAMSHALE™ Completions, Cameron focusing on emerging markets, knowledge and technology transfer, and commercializing new technologies for unconventional shale plays throughout the world. Thomas has multiple United States patents for development of downhole drilling and well intervention tools and received the OTC Spotlight on New Technology Award and the Hart’s Meritorious Award for Engineering Excellence. Thomas holds a Bachelor of Science in mechanical engineering from Texas A&M University and a Master of Science in technology commercialization from the University of Texas.
Craig Young Mr. Young has over 30 years of experience with oil and gas operators. Craig spent 16 years with Marathon Oil Company, 10 years with EOG Resources, and several years with smaller operators. Mr. Young specializes in Drilling and Completions. Mr Young has been drilling and completing horizontal wells since 1989 and specializes in shale resource plays. Mr Young was involved with EOG’s development of the Barnett Shale, Eagle Ford Shale, and Wolfcamp Shale developments. Craig was Operations Manager in San Antonio during EOG’s Eagle Ford Development. Mr. Young has worked in the Eagle Ford South Texas, Eagle Ford Central Texas, Premian Wolfcamp, Delaware Wolfcamp, and Delaware Bone Springs areas. Craig is currently working with Cameron as a consultant in their Resource & Operations Improvement Team.