North American operators are turning to locally sourced sands as a way to reduce proppant freight costs. “Companies are buying the cheaper sand either because they believe that there’s not enough impact on production to warrant additional costs of white sand, or because they simply have to lower up-front costs, sometimes even at the expense of sacrificing long-term production to complete wells,” Samir Nangia, Director of Consulting within the IHS Energy Insight group, said.
IHS data shows that average frac sand mass per horizontal well in the US onshore market increased by 24% in 2015. Much of the increase is attributed to increasing well lengths in the Appalachia, Bakken, Permian and Eagle Ford.
In fact, 35% of total sand proppant demand is now locally sourced, according to ProppantIQ, a proppant market analytical service from IHS. Local sands, however, typically score lower on crush strength, roundness and other key metrics than the industry’s standard sand proppant – northern white sand. Northern white sand is 100% Silica and typically mined in Wisconsin, Minnesota and Illinois. It still accounts for 65% of total sand proppant demand and is preferred for its higher quartz composition, which provides the desired higher crush strength.
Other types of proppant that must undergo higher-cost manufacturing processes, such as ceramic or resin-coated proppants, remain niche markets. In North America, ceramic proppants now account for just 1% of all proppant demand, while resin-coated proppants account for 3%, according to IHS. “Ceramic usage is mostly in the Bakken, and frequency of use there is declining as activity moves away from the Middle Member Bakken play and into the Three Forks,” Mr Nangia said.
Proppant demand in the future will depend a lot on production performance over the next couple of years, he added, as operators monitor the performance of the lower-cost, locally sourced sands. “When people try something cheaper, they will typically stick to it unless it can be proved that the more expensive stuff just worked much better,” said Thomas Jacob, Unconventional Oil and Gas Consultant for IHS. For example, wells in deeper plays such as the Bakken and Eagle Ford used to be completed with ceramic proppant. But when companies tried white sand without noticing any detriment to production, they stuck with it. “If local sand truly works and production at the back end is not sacrificed as a result of using it, then I would expect people to continue using it.”
Operators are also paying much more attention to using proppants that will optimize recovery for specific basins. “It’s not the best proppant that you need. It’s the right proppant to match the geology of the well,” said Scott Sustacek, CEO of Jordan Sands. “You might not need to purchase a ceramic when a northern white will do, and you might not need to purchase a northern white when a brown will drive the well economics you need,” Mr Sustacek said. “I think the entire cost/return model of well drilling has come a long way in terms of matching proppant to the geology.”
Further, operators are improving their well completions by increasing proppant volumes, extending lateral lengths and shortening fracture intervals. Although North American drilling activity has fallen by approximately 70% since late 2014, proppant demand has dropped by approximately 50% in the same period, according to IHS.
ProppantIQ’s data shows that, on average, the amount of sand proppant pumped per horizontal well in the US Lower 48 has increased by 210% since 2011. However, part of this higher proppant usage per well is due to what IHS calls high-grading: The industry is fracturing only the very best rock, and this rock benefits the most from greater usage of proppant. “During the downturn, E&Ps have retreated to the places with the best acreage, which produces many times more than lower-quality rock, and obviously, this rock is just more economical.”
To reduce rail and trucking costs, Jordan Sands has studied locations of sand mines in relation to customer drill sites to better manage logistics. It has also increased rail-car sizes to maximize carrying capacity. So far, such efforts have resulted in a 15% reduction in sand production costs for the company.
Regardless of the increased volumes used per well, total proppant demand has fallen in North America due to the significant drop in drilling activity. It will likely continue to fall until the market picks up. In 2015, North American companies used 100.7 billion lb of proppant, compared with 120.2 billion lb in 2014. For 2016, ProppantIQ is predicting an additional 43% drop in demand, which equals 57 billion lb.
Although cost reductions remain a core focus for operators and their supply chain, there is little that proppant companies can do to reduce the cost of white sand. Logistics is one of the few variables that companies like Jordan Sands can tackle for meaningful cost reductions.
For example, Mr Sustacek said his company is studying the location of its sand mines in relation to customer drill sites in order to reduce rail and trucking costs. The company is also using rail cars to maximize the amount of proppant carried to the wellsite in each trip. “We’re trying to help them compress the supply chain and squeeze out excess cost wherever we can.” These changes have led to a 15% cut in sand production costs, Mr Sustacek said.
Fairmount Santrol has seen locally sourced sand proppants gain popularity over the past couple of years. Northern white sand can be more expensive as it must be transported from the northern US to well sites in other regions.
Some proppant companies are looking to boost business by increasing the value of sand through resin and polymer coatings. These coatings are applied to about 3% of sand proppant in North America, according to ProppantIQ. Fairmount Santrol, for example, uses resin coating to increase proppant strength and provide better proppant flowback control.
The company also uses polymer coatings to help distribute proppant evenly throughout the well. In 2014, the company commercialized Propel SSP, a proppant transport technology, to help proppant particles flow into and fill fracs more evenly and efficiently at any pump rate. “The historical challenge is that companies either need to have very high pump rates or high viscosity to be able to transport proppant without it settling in the wellbore or duning just outside of the perforation when entering the fracture,” said Brian Goldstein, Fairmount Santrol Product Director. “When you’re able to transport proppant at any pump rate with a relatively low fluid viscosity, oil and gas operators can optimize frac fluid systems and achieve a more effective frac geometry.” After the proppant is placed inside the well, the polymer will break down and flow back to the wellhead, allowing the formation to close on the proppant.
In the second half of 2015, Fairmount Santrol used the polymer coated proppant in a six-well field trial in the Three Forks and Middle Bakken formations in North Dakota’s Williston Basin. Independent operator Enerplus Corp compared the trial wells against five offset wells. These offset wells used typical northern white sand with a common crosslinked gel fluid system.
The initial 90-day oil production of the trial wells increased by an average of 39% compared with the offset wells, according to Fairmount. The increase was attributed to more uniform proppant distribution throughout the wells’ pay zones with the use of the technology. Additionally, fluid additive consumption was reduced by 77%, primarily due to the elimination of viscosity modification additives, Mr Goldstein said. Pumping time was reduced by 14%, as the proppant was more efficiently placed in the formation.
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