Sourcing, treatment & disposal: The water challenge for shale gas operators
The volumes of water required to fracture a well, and the volumes and characteristics of the wastewater produced from shale gas operations, make water management central to shale gas production.
by Melissa Stark, Accenture
The volumes of water required to fracture a well, and the volumes and characteristics of the wastewater produced from shale gas operations, make water management central to shale gas production. Shale gas operators are faced with a number of options regarding the sourcing of water and the disposal of wastewater. Local regulatory frameworks, the characteristics of the returned water, and the cost-effectiveness of different options constitute some of the drivers behind these choices. This landscape is a constantly evolving one as players explore the most effective water management options available to them and the overall industry grows and matures.
Water plays a key role in each stage of the shale gas well life cycle, from well development to production. The key challenges for operators are sourcing sufficient volumes of water required for drilling and fracturing each well and effectively managing the volumes of wastewater generated.
Water used in hydraulic fracturing is sourced from surface waters (lakes and rivers), groundwater (wells, aquifers), municipal supplies, and from wastewater from previous fracturing processes. Once collected, the water is hauled or piped to the site where it is stored in lined impoundments or tanks until it is used in the drilling and fracturing stages.
The volumes of water required in shale gas production vary considerably from well to well. The FracFocus website, which details the water use of wells across the United States, shows the variety of volumes required across different wells. Factors influencing this total volume will include:
- The depth, length and number of horizontal segments fractured: The longer the segment, the more water is required for the fracturing process. There is a trend for longer horizontal segments: Two years ago, these would have been approximately 3,000 feet long — with advances in technology, these can now cover up to 6,000 feet.
- The geological characteristics of the shale play: shale plays differ widely in their geological characteristics (depth, thickness, total porosity) resulting in different water requirements. The Haynesville Shale (3,200 to 4,110 meters in depth), for example, requires on average one million gallons of water during the drilling phase compared to 60,000 gallons for the Fayetteville Shale (300 to 2,100 meters in depth).
Figure 1 shows a range of 3-4 million gallons of water, as an average, required to drill and fracture a well. The fracturing stage is the most water intensive, using up to 90 percent of the total water used. Despite public perceptions to the contrary, these water requirements are low when compared to other sectors (agricultural, industrial), and when set against the water intensity of other forms of energy. Nevertheless, access to water sources is likely to become more of a constraint for operators in arid regions facing growing depletion of water resources, and in areas where water flows and availability follow seasonal variations.
Following the fracturing, varying volumes of the injected fracture fluid will flow back to the surface ("flowback water"), mixed with "formation water" containing dissolved minerals from the formation. Although there is no formally agreed definition, flowback and produced water are jointly referred to as "wastewater." The water recovery rate, that is, the amount of wastewater recovered from the volume injected as part of the hydraulic fracturing process, both in the short term (flowback water) and in the long term (total produced), varies by well and by shale. There are "dry" shales with lower water recovery rates (15–25 percent of the injected water returning to the surface), such as the Marcellus, and "wet" shales with high water recovery rates (up to 75 percent), such as the Barnett.
The flowback water constitutes the highest volumes of wastewater over the life cycle of a well. It can represent a million gallons of water or more over the course of weeks with the majority captured in the first several hours to several weeks.
The flowback water contains a number of constituents, depending on the fracturing fluid and the shale formation and varies dramatically across shale plays. The flowback water will contain additives from the drilling and fracturing fluids (e.g, biocides, scaling inhibitors, friction reducers) as well as salts, organic compounds, sulphates, and metals (e.g., calcium, magnesium, barium) present in the formation, and Naturally Occurring Radioactive Materials (NORM).
NORM is brought to the surface in the drill cuttings, in solution in the produced water, or in scales or sludges. The levels found in wastewaters are significantly lower than the safe limits of exposure; however, these should be monitored carefully in case concentrations increase during waste treatment. At concentrations higher than regulatory limits, the material must be disposed of at licensed facilities.
A further characteristic of this produced water is its salinity, measured in levels of Total Dissolved Solids (TDS). These levels vary between the shales, depending on the rock strata and the geologic basin, from brackish to saline to brine.
Following this high initial flow, the levels of wastewater generated gradually decrease as production begins. Following field development, the returned water is produced in small quantities by a multitude of different wells over longer periods of time. The logistics challenges involved in managing these small volumes of water produced by multiple sources over longer periods of time will be different from those presented during field development — and the opportunities to reuse the wastewater are also different.
Treatment, Disposal Options
The options available to operators vary depending on the availability of underground injection wells, the volume of flowback, the characteristics of the water, and the local regulatory framework.
This method of disposal of produced water is normal practice in conventional oil and gas production. Operators can inject their wastewater in underground injection wells, or Class II wells, or pay a third-party commercial disposal company to take their water and inject it into a disposal well. In the United States, either type of well must be permitted by a state agency or the Environmental Protection Agency through the Underground Injection Control (UIC) program. These underground formations are situated in porous rock formations, thousands of feet underground.
As the cheapest disposal option for flowback and produced water, and with approximately 200,000 underground wells in the United States, disposal in underground injection wells is one of the most widely used, and most cost-effective, wastewater management options. Produced water is either hauled to these underground disposal sites or piped.
Flowback water can be collected and reused in a closed-loop system. When considering water reuse as a water management option, two characteristics of the returned water will be examined: the water recovery rate and the water quality.
The water recovery rate (i.e., the volumes of returned water compared to initial water injected) is particularly important as this will affect the volumes of water required to supplement the returned wastewater to meet the volumetric requirements of the drilling and fracturing stages as well as the on-site water storage requirements. Water recovery rates vary between plays and there are also considerable variations within the plays.
The large volumes of water required present an operating challenge when only a percentage of injected water returns to the surface, for instance, in dry shales such as the Marcellus, where the formation characteristics tend to trap and bind the water in the formation (known as "imbibition"). The focus of water reuse efforts is on flowback water since this presents the highest volumes over short periods of time. During development, these volumes will need to be supplemented by freshwater to reach the volumes required — even in a closed-loop system. Later in the life of a field, these wells will start producing small amounts of water over longer periods of time — making reuse less attractive.
The quality of the returned water will shape the decision on the levels of treatment required to reuse the water (simple filtration or dilution, or further treatment) without affecting well productivity. There are wide variations in the geochemistry of flowback water used for recycling and reuse in closed-loop systems. In particular, the constituents of concern include:
- Concentration of Total Dissolved Solids (TDS): Very high TDS increases friction in the hydraulic fracturing process (bad for fracturing).
- Levels of Total Suspended Solids (TSS): The returned water should be treated to a level where suspended solids will not cause scaling in the injection train or clogging of the pore space in the formation. High TSS could also reduce the effectiveness of biocide.
- Concentrations of scale-forming chemicals: Levels of scale-forming chemicals (including barium, calcium, magnesium) should be limited as these can have a negative impact on equipment and infrastructure.
- Levels of microbial constituents: Biological growth should be controlled, as microbes can increase the likelihood of plugs being formed in the wells.
Some operators will choose a simple dilution and/or filtration of the flowback water. In some cases, this will suffice to meet the requirements of the fracturing fluid. However, filtration only removes large solid particles (TSS) and will not address metals, organics, or chemical constituents in the water, including high concentrations of TDS. In some cases, other treatments will be required to allow for reuse in fracturing fluid or even to drilling fluid quality depending on the operator’s objectives.
Treatment to Freshwater
Treating the water to produce clean freshwater is the most expensive management option, due to the technologies used and the pretreatment required. Evaporation and crystallization technologies are costly and require high energy inputs. However, these technologies present the best options for treatment of brines, in particular for removing the high levels of TDS.
Depending on the shale’s characteristics and regulatory requirements, operators are likely to use the lowest-cost option allowed by regulation but with a preference for reducing water use or for water reuse or water treatment in cost-neutral situations. Operators have a number of choices for reuse/disposal of wastewater:
- Haul to disposal site (landfill or underground injection)
- Filter and reuse
- Treat to drilling fluid quality
- Treat to surface disposal (where this is allowed but mostly not allowed now)
- Treat for agriculture use
- Treat to freshwater
Furthermore, these choices are constantly evolving, with the drivers likely to change in the future. The choices and the composition of the wastewater and competing alternatives will determine the mix of technologies.
About the author: Melissa Stark is a managing director with Accenture’s Energy industry group and the lead of the group’s new energy practice. She was the research lead for Accenture’s recent report entitled "Water and Shale Gas Development, Leveraging the US Experience in New Shale Developments." This article was based on the report, which is available for download here: www.accenture.com/us-en/Pages/insight-new-energy-water-shale-gas-development.aspx.