- Growth in shale production has brought with it growing public awareness of the environmental impact of oil and gas extraction from hydraulic fracturing operations.
- Improved water treatment technology and in-basin use of frac sand are rapidly becoming industry best practices.
- Many operators are moving to retire old diesel-fueled equipment, replacing it with cleaner all-electric equipment.
Fracture stimulation of shale rock, conventionally known as “Fracking or Frac’ing,” has turned America into an energy powerhouse, over the last 12 years. This bounty from shale has enabled the country to provide much of its own energy needs with a substantial amount left over for export. Particularly in the form of natural gas as LNG.
Growth in shale production has brought with it growing public awareness of the environmental impact of oil and gas extraction from shale strata. To coax oil and gas into flowing from the tightly compacted rock from which shale is constituted, an enormous amount of resources are expended on each well during fracking. A typical, 2-mile-long horizontal well will require-
- 20 million gallons of water
- 3-million pounds of sand
- Several thousand truck trips to the location
- Directly consuming 200,000 gallons of diesel
- Emitting ~ 2,400 Tons of CO2 through burning diesel
The case has been made in governmental and investor circles that this burden on the environment must be reduced. Toward that end, the EPA has mandated emission standards for non-road diesel engines that require the use of Tier II and Tier IV engines in fracking operations. These substantially reduce CO2 emissions from earlier equipment.
Seeking to reduce the carbon footprint of fracking, oil companies have been increasingly looking for ways to improve the ESG ranking of their operations. These efforts have focused primarily on several areas, including water recycling, emissions reduction at the well site, and the use of in-basin sand to eliminate drying and long-haul transport. Companies that provide fracturing services to oil companies have found it incumbent in their business plans to upgrade their equipment beyond current government standards in furtherance of meeting operator goals in the case of emissions. With the challenge of water recycling, new technologies have been implemented to drastically reduce the amount of freshwater used in fracking operations.
In this article, we will look at how key elements of the fracking industry are working to help the industry accomplish these goals.
The vast amounts of water used in frack operations have required a shift in thinking from what was prevalent just a couple of years ago. The old mindset was to send water flowing back from the well and water produced with oil and gas to disposal wells. The increase in induced seismicity, particularly in the Permian basin that has resulted over time from over-injection has brought this issue front and center into the public’s consciousness and brought with it rule changes by the Texas Railroad Commission-TRCC.
The TRCC is the state agency that governs permitting of oil and gas wells in Texas, as well as the disposal wells used previously to inject frac and produced water into permeable reservoirs. The linked WSJ article above notes that the agency sharply reduced injection in key areas of the Midland basin.
“The Railroad Commission in September curtailed the amount of water companies were permitted to inject into some wells near Midland and Odessa, and has since suspended some permits there and expanded the restrictions to other areas. It has said the suspensions are in effect until further notice.”
For companies operating in these areas, such as Chevron, (NYSE: CVX), and Coterra Energy, (NYSE:CTRA), trucking water to new disposal sites, would have increased field expenses by tens of millions of dollars annually. The obvious answer is recycling on-site and storage of treated water volumes for reuse in future fracking operations.
One company that has led the charge in this effort from the services side, is Tetra Technologies, (NYSE:TTI). Tetra is a leader in treating large volumes of flowback and produced water with mobile recycling equipment that can be quickly transported to an operator’s site, erected, and put in operation, processing as much as 40,000 barrels a day often with just a single field representative.
In the picture above taken by the author, a 40,000 bbl static tank is shown that is supplied by flowback and produced water from local wells.
This photo depicts the chemical stabilization of the water taken from the tank in the previous picture. Solids are removed by sparger-type tank directly behind the “Swiftwater” tank (a division of TTI), and then the clarified water is sent to a million-barrel lined berm tank shown in the background (behind the pickup trucks). (Author’s files)
The water that is clarified and put into the million barrel tank, is shown at the extreme left in the picture above, and had a turbidity of value of 19 NTU-Nephelometric Turbidity Units, clearer than tap water in many cases. The picture at the right and center shows samples in intermediate stages of treatment. (Author’s files)
This technology appears to be rapidly gaining client acceptance and implementation, as noted by Brady Murphy, Tetra’s CEO, in the company’s 2-Q quarterly analyst call-
“We are seeing significant demand for produced water recycling to help our customers reduce disposal costs and address increasing seismicity events with 4 new recycling projects added in the second quarter. In the Permian alone, we recycled 571 million gallons in the second quarter, up 62% from a year ago and up 17% from the first quarter of 2022.”
This is a huge market application. With roughly 8,000 new wells annually, and about 40,000 existing ones, there are as much as 11 billion barrels of water needing treatment in the Permian basin alone.
Emissions reduction from frac spreads
In advance of threats promulgated by the EPA this summer to declare a “non-attainment” crisis in the Permian, which would mandate activity reductions, the fracturing service industry has seized the bull-by-the-horns in the effort to improve ESG metrics. Much of the older Tier II diesel equipment has been retired, and the Tier IV equipment is being upgraded to DGB-Dynamic Gas Blending. Frac pumps that are configured to this standard use local natural gas as a part-feedstock to reduce the amount of diesel being consumed in the fracturing operation.
The graph below, taken from a pamphlet distributed by U.S. Well Services, (NYSE: USWS), a leading provider of fracturing services, shows that depending on the load up to 70% of diesel demand can be shifted to natural gas. This results in significantly lower overall carbon emissions than just burning diesel alone.
The shift to DGB frac equipment has been slowed by budget exhaustion on the part of service companies, like U.S. Well Services-being acquired by ProFrac Holdings, (NYSE:PFHC), Liberty Energy, (NYSE:LBRT), and others. Margins, while improving are not yet back to 2019 levels. Additionally, CEO’s are very reticent to allocate new growth capital, which can run to $40-$60 mm per fleet as their balance sheets are just recovering from the 2020 downturn.
Liberty CEO, Chris Wright commented in regard to an analyst question on fleet reactivations and upgrades-
“We don’t have any plans to add capacity per se. Our plan and we do have a plan on (Tier II) fleet modernization is sort of a continued gradual program. But I would say the migration to next-generation fleets, the economics are going to pull that pretty strongly. These next-generation fleets have meaningfully lower emissions.”
The next generation of fracking will be driven by all-electric equipment run off electricity generated in the field, most likely from natural gas. A number of companies, driven by premium pricing offered by ESG-conscious clients who want the latest and best equipment available, are rolling out these all-electric fleets.
The leader in this area is U.S. Well Services which just announced in May, 2022 a significant Permian basin contract for its Nyx CleanFleet electric pumping spreads. By the end of next year, USWS expects to have a ~dozen of these electric fleets working for ESG-conscious clients. Other companies including Liberty Energy will be following suit with their Digifrac offering.’
The use of “in-basin” sand is another step change improvement from the original frack model, which drew ultra-pure white sand from Wisconsin to the Permian by rail car. It was then moved on demand from centralized depots to field locations where it was to be used, requiring dozens of truck trips. Wisconsin sand known as “Northern White,” was prized for its sphericity, and crush resistance. Over time operators began to experiment with local, reddish sand, to lower this transportation cost. At first drying it in centralized locations to reduce weight, at an enormous fuel cost. Now wet sand is being taken from sites adjacent to the fracking operation, cutting last mile costs to the bone and reducing the environmental impact.
In an effort to reduce “last mile” shipping costs a company called PropX (acquired by Liberty Energy in 2021), has been at the forefront of minimizing these costs. This company containerizes this local sand for maximum dustless deployment at the rig site.
Shale drillers like Devon Energy, (NYSE:DVN) are also rethinking sand logistics. Devon last year introduced a “mobile sand mine,” to move sand logistics closer to the rig location. Clay Gaspar, COO of Devon commented in the Q-1 earnings call about the impact of this mobile sand mine on Devon’s Delaware basin operations-
“This mobile sand mine is the first of its kind in the Delaware Basin and is expected display up to 25% of our profit requirements in the basin this year. In addition to providing a certainty of supply, this mine could save us up to $200,000 per well relative to the rising spot prices we are experiencing across the basin as activity picks up and sand supply is tightened.
Equally important, this mine also has significant environmental and safety benefits due to the need for fewer trucks on the road. And it eliminates the combustion related emissions associated with drawing the sand that occurs in normal mining processes.”
Fracking is necessary for America’s shale miracle to continue. Without it, shale production would drop precipitously. The natural decline rate of shale reservoirs is about 30% per year, so in three years of no fracking U.S. onshore production could be back where it was in 2010. In that case, instead of importing ~5-6 mm BOPD from the Middle East, we could be needing 12-14 mm BOPD. The bad news is they don’t have it to spare, and we would be in a bad situation. OPEC+ has been under-lifting its quotas by as much as three million barrels a day. There is no spare capacity.
Necessary as fracking is to maintain our lifestyle and energy security, the industry is committed to doing it while meeting the highest ESG standards obtainable. The industry has demonstrated the ability and willingness to improve on old practices and to be good stewards of increasingly scarce resources, such as water. Most oil companies are now using 80-90% recycled water in their fracking operations.
On the emissions side, the industry is spending hundreds of millions of dollars to upgrade older Tier II equipment to Tier IV DGB status, and eventually replace that with electric frac equipment.
As in the case presented by Devon Energy, shale drillers are taking action to reduce the ESG impact of exploiting shale resources. Moving the mine to the location is a dramatic change from the model of just a few years ago. Going forward the fracking industry will be a partner in the production of oil and gas using the best-demonstrated technology with much less environmental impact than just a few years ago.