When global business consulting giant Accenture finished a recent treatise on shale oil and natural gas development, it identified eight key factors needed to make exploitation of shale viable, and the first three are found in abundance in successful U.S. shale plays from North Dakota’s Bakken to Texas’ Eagle Ford. They are geology, land considerations and the existence of an unconventional energy resource service sector.
The unwritten explanation for the roaring production in places like North Dakota is centered on these three elements. Two others are takeaway pipeline and processing infrastructure, along with financing, both of which have been written about extensively in conjunction with the shale revolution. The lay of the land, so to speak, has gotten less attention.
Patric Galvin, a business consultant and entrepreneur, is focused on one of the essential ingredients helping drive shale plays – sand. And he has chosen to produce and market it within about 300 miles of some of the largest U.S. shale developments.
Galvin’s South Dakota Proppant LLC is bidding to advance the proximity of the essential ingredient for hydraulic fracturing (fracking), the well stimulation process that is driving the success of the production in the Williston Basin in North Dakota and the Denver Julesburg (DJ) Basin in Colorado.
If Galvin is correct, he will do it in an area that an earlier state geologic survey in South Dakota indicated couldn’t be developed as a sand mine. And he will do it on federal lands, assuming he can get the permits ultimately required for commercial extraction on lands managed by Uncle Sam.
In mid-2014, the bulk of the sand used in fracking in North Dakota came from one of three nearby states – Minnesota, Illinois and Wisconsin. Northern White was the preferred sand, although some hickory sand was being used, shipped by rail from parts of New Mexico and Texas. The bulk because of proximity, however, was coming from the Upper Midwest. A constant stream of rail cars delivers to depots around the Williston Basin. From there, trucks haul it over heavily traveled highways and roads to well sites.
An increasingly popular alternative is ceramics, which come from the Far East or other parts of the United States by a combination of ocean-going freighter, rail cars and eventually truck loads that are part of the extensive transportation network bringing materials and equipment to the booming Bakken/Three Fork shale play.
In a similar vein, companies like Tensar International Corp., are working to refine and enhance road and drilling site construction, offering technology, materials and a process for lowering construction and long-term maintenance costs. Atlanta-based Tensar calls its geo-synthetic road and ground improvement TriAx®, and is making some gains in its use and familiarity in North Dakota, according to Scott Whaley, a professional engineer and regional sales manager, who Tensar in mid-2014 transferred to North Dakota. The company has a presence in major shale play areas besides the Williston Basin’s Bakken/Three Forks, covering the Marcellus and Eagle Ford shale plays among others.
Whaley points out that in booming shale production areas there is a lot of potential work for Tensar beyond the direct oilfield and pipeline installations, since the fossil fuel boom brings an accompanying economic surge that equates to more roads, schools, homes, businesses and general transportation needs. Tensar’s “geogrid” mesh-like material placed over subgrades allows for 60% less granular fill to stabilize an access road, well site or pipeline right-of-way. It also works for processing and compressor plant sites in the fast-expanding midstream network required to move the shale oil and gas output.
For every pipe put in place to haul away the robust output of the shale revolution, there are just as many hours and dollars expended to find and produce the energy commodity. Tensar potentially serves all of those needs.
Some of Tensar’s and other companies’ solutions likely will be applied in areas where there are a lot of clays like in the northern part of the Bakken play, a veteran Williston Basin engineer said. He characterizes the glacial till as “almost impossible to consolidate” when it is wet. For well site developer/operators, dealing with frozen soil has always been a problem, but it is even bigger now that multi-well pads are being developed, and the well sites have to be in place for much longer periods.
The multi-well pads might be there for six to eight months while the drilling rig is moved around constantly. Without the right soil design and preparation, rigs can shift and tilt, the consulting engineer cautions.
“There is an opportunity [for Tensar’s technology] to stabilize and make the well pad moves easier,” says Whaley, who classifies Williston Basin soils as varying from location to location. But what he thinks is more important is the lack of quality of the fill material used on road and well sites.
“A lot of the oilfield services companies are using scoria, or “clinker,” which is a marginal fill material up here, particularly considering the loads being put on it. This is a pit-run, sandy material and a lot different than what would be found elsewhere, so this creates another opportunity for our product,” he says.
Transitioning to drilling operations, the focus nowadays shifts to hydraulic fracturing as the critical part of developing a money-making production well. And within the fracking process the absolute key is the proppant used, according to North Dakota-based Monte Besler, an engineering consultant specializing in the fracking process with his FRACN8R Consulting LLC, firm. While Besler is an experienced engineer in a number of oil and gas upstream areas, his specialty is fracking the Bakken formation, something he has been involved in since 1981.
An advocate for the use of ceramics in most fracking jobs, Besler says operators vary greatly in what they use – from 100% ceramic proppant to 100% sand. Besler bills himself as a “completion specialist,” noting that finishing wells in the Bakken has taken on a combination of art and science with the pressure to do the job ever-more quickly, efficiently and economically.
In general, well completion times have been slashed over the past two or three years in North Dakota, according to the state’s chief oil and gas regulator, Lynn Helms, director of the state Department of Mineral Resources.
The “grease” for this ever-increasing efficiency drive in proppant, as many of the workers in the field will confirm. “More proppant makes better wells, and more fluid makes better wells,” says Chris Wright, CEO of Denver-based Liberty Resources and its Liberty Oilfield Services LLC unit.
For short-term performance from a given well, just about any proppant will work for the first 90 days, but the quality of the proppant will affect the long-term performance of a well, says Mark Pearson, Liberty Resources president, as he and Wright teamed up during a quarterly earnings conference call in mid-2014.
Besler calls proppant “the single most important thing in a fracking treatment,” contending it is the only thing that actually improves production in the well. “Everything else is either a conveyance for the proppant, or a way to pump it, or chemicals used to mitigate some of the negative effects of other chemicals, such as the jelling agents, or to mitigate some incompatibility between formation fluids and the fracturing fluids.”
Besler’s conclusion: everything else, in contrast, is either damaging to a well’s production, or at best, neutral.
As a result, the market, logistics and handling of sand or ceramics is now watched closely in the increasing number of productive shale plays in the United States. Infrastructure concerns are expanded. Oilfield services are expanded. The overall well logistics from design through completion are that much more complex.
Liberty’s CEO Wright spends a good deal of time on investor calls talking about sand. An example of a recent call:
“The sand market has tightened since mid- to late-2013. Since that time [very short], several things have tightened the market – an increase in frack intensity, the amounts of sand used have been increasing, speed of drilling has ramped up, and then a very bad winter [2013-14] and rail problems have contributed to a tighter sand market.”
He adds that the market had tightened at both the mine and wellsite, but mostly at the latter.
In late August, aggregate U.S. fracking sand consumption was projected to reach 78 million tons a year by 2016, according to a study by Raymond James & Associates Inc., “North American Sand Rush: An Underappreciated Pillar of Growth.” The report estimated a 22% compound annual growth rate for sand through 2016. Various logistical problems in getting the sand from its production areas to the fast-growing shale basins are also discussed in some detail in the 41-page report.
Besler would recommend steering away from sand and focusing on ceramics. Operators, such as Liberty, are still “experimenting,” according to Wright.
“A lot of the fracking jobs I design are 100% ceramic,” says Besler, noting that some operators use 100% sand, such as EOG Resources, which owns its own sand mine supply. “I’m not sure it is a good practice, but when senior management decided to go all-in on sand mines, it pretty much dictated to their engineers they are going to use sand.”
Sand, ceramics, chemicals and water are what make up the fracking ingredient. Water is about 99% of the liquids involved. Chemicals usually amount to about 0.5% and then the proppant. Galvin, the South Dakota Proppant developer, says on average a fracked well requires 5,000-8,000 tons of sand, but as the industry moved to more sophisticated and continued “re-fracking” processes, those averages could increase considerably. Besler estimates the average amounts of proppant used in each well is 3-4 million pounds (1,500-2,000 tons).
“There are a few places using that much proppant per well [5,000-8,000 tons], usually all silica sand. Often they are trying to mimic EOG. What they don’t have is their own sand mine like EOG. The amount of proppant-per-well is increasing, but so is the number of stages-per-well, so that is likely the main cause for increased total proppant use-per-well,” Besler says.
“It comes down to a value proposition, and that is one of the things we are studying,” says Liberty’s Pearson. In the first three to six months of production, the difference in proppants is not that great, according to Liberty’s experience. “[However] over the life of the well, what is going to be the answer?” he asks.
“This is something we continue to study. It is not beyond future possibilities to dump 20 million pounds of ceramics in a single well. It also could be 20 million pounds of sand or 20 million pounds of a blend.” Pearson emphasizes Liberty is still open to what the answer is, adding he does not know the answer. It is not a rhetorical query.
“There is no one, short answer to the question of whether sand or ceramics is better,” he says.
In terms of sand’s use in proppant, there are many arcane considerations in terms of the silica itself, such as its sphericity and solubility, along with its geographic location.
In mid-summer 2014, Galvin was pressing forward with his acquisition of acreage in South Dakota, adding 800 acres to increase his total of 1,750 acres, and signing preliminary agreements with several exploration/production companies seeking sand supplies that meet industry standards and specifications. Separately, U.S. Silica Holdings Inc. gained local approvals in Fairchild, WI to develop a sand-mining operation, eyeing a 3 million tons/year facility in close proximity to a Union Pacific Railroad shipping terminal.
U.S. Silica CEO Bryan Shinn cites the need for new sand capacity nationally, saying demand keeps growing for sand in general and Northern White frack sand in particular, from all the major U.S. shale basins.
Earlier in 2014, U.S. Silica and Union Pacific agreed to build a Permian Basin rail-accessible silica sand storage facility in Odessa, TX, a 20,000-ton installation that is supposed to be ready by the end of 2015. In 2012, U.S. Silica partnered with S.H. Bell Co. to build a facility in Ohio for serving Appalachia operators and with BNSF Railway to build sand storage facilities in San Antonio to serve Eagle Ford Shale operations.
For Galvin, who is attempting to set a first in South Dakota, it is a matter of logistical advantages in his proposed mine, which holds deposits that differ from other areas of the state that scientists have ruled out for their proppant potential.
He says his location has sand that meets American Petroleum Institute (API) standards, and his geographical location can save operators in the Bakken or the Niobrara Shale plays as estimated $50/ton in delivery costs.
“That is over $50 million annually for our clients,” says Galvin, who adds he has taken 40-mesh screen sands from Wisconsin from a sampling of that state’s offerings during the summer and compared them microscopically with South Dakota samples from his proposed mine site. “[Our analysts] couldn’t tell the difference – it was very similar in roundness and sphericity, along with being very similar in strength.”
And then there are the alternatives to naturally occurring sand – man-made ceramics – which some hydraulic fracturing engineers, such as Besler prefer. Many of the ceramics are made in various places around the world by firing clays, particularly clays high in aluminum oxide (alumina) content. When fired they form little pellets, according to Besler, that are much stronger and rounder than quartz.
Guys like Besler know their ceramics for proppants – lightweight, intermediate strength and high-strength varieties. Each cluster around various levels of specific gravity, says the former senior consulting engineer with Hohn Engineering PLC, who was once a production engineer for Hess and district engineer for Halliburton. The higher the alumina content, the higher the strength of the proppant, he says. Ceramics come from various places. China has been a significant supplier, although Besler prefers U.S.-made supplies.
Manufacturers get into an arcane level of detail in their designs and methods for making proppant. A common 20-40 mesh range for the API specifications means nothing is finer than 20 or coarser than 40, but some makers have manufacturing processes that naturally turns out an 18-40 range. They can offer it cheaper because they don’t bother to sift out the 18 mesh.
Ultimately, the unique aspects of the wellsite and fracking requirements must be meshed with the proppant. Here is where it becomes mostly science, along with the experience of the fracking engineers.
Technology continues to advance the E&P process, particularly well completions. The use of “staging” has picked up, according to Besler, who sees it as the ability to isolate within the well bore with ever-greater confidence. These are continuous improvement items, including multi-stage systems allowing operators to open multiple fracking stages at the same time within a given interval, he says.
“Generally, stages refer to the selective fracturing of intervals along the horizontal well,” Besler says “The intervals start at the toe of the lateral, or the deepest portion, and progress sequentially toward the heel of the horizontal lateral, the part of the well nearest the vertical wellbore. Improving the fracture conductivity around the wellbore helps overcome the reduced flow area created by the [horizontal drilling process].
“This can be accomplished by using better quality proppants designed for the formation conditions, larger mesh proppants when practical, avoiding over-displacement of the proppants, and maximizing the proppant concentration in that critical fracture and wellbore intersection,” he says.
Various other factors are important in determining the right type of proppant to use. Those include: permeability of the given geology; closure stress, or the tendency of a given fracturing to seek to close back up; and temperature (2300F or higher), recognizing that deeper, unconventional formations will have higher temperatures and stress.
“With sand proppants in high temperature, the conductivity tends to erode, where with ceramics the alumina makes them more resistant,” cautions Besler, while noting that the ceramics are not immune to it. “Ceramics loss of conductivity over time is much lower. That is part of the geology you are dealing with and the main factors that come into play.”
Materials science and engineering increasingly are an essential part of the shale revolution as exemplified by respected research organizations like Battelle Laboratories that offer a growing array of services, focusing on well completions and integrity, and advancements in stimulations for production. Ultimately, the work will require more world-class science and engineering, something U.S. shale plays are increasingly attracting.
Author: Richard Nemec is a Los Angeles-based correspondent for P&GJ. He can be reached at: email@example.com.