Oil and gas operators have a complicated relationship with water. Is it a valuable resource or a necessary evil? Turns out, it’s both. On the one hand, water is necessary for drilling, fracking, and stimulating production. On the other hand, water must be sourced, transported, and managed for these activities to be successful. To make matters worse, most wells produce water in varying amounts that must be properly handled and disposed of due to its salinity and chemical composition. And, water management costs are on the rise. In this second part of our series on water, we’ll look more deeply into the topic of water management in the oil and gas industry and explore potential options for ameliorating the complex relationship between oil and water.
Water produced during oil and gas operations
In Oil and Water – Part 1 we looked at the sources and use of water for drilling and fracking wells in Oklahoma. Today, we’ll focus on the water resulting from these operations. The first is Flowback, which refers to the water-based solution flowing back to the earth’s surface from fracking or re-stimulation processes. Aside from water, flowback solutions typically contain chemical additives, mud, clay, as well as dissolved minerals, salts, and metals. Flowback is a key stage of the fracking process, and the solution recovered from the wellbore during this process must be properly managed to avoid contamination of the surrounding area.
The second type of water resulting from operations is referred to as produced water. Water naturally occurs in the underground formation along with oil and gas, so during the production phase, this water is also extracted from the subsurface. Produced water is also referred to as “brine” due to its typically high salt or mineral content. This water may also contain constituents associated with the drilling and fracking processes as well as other organic compounds, and radioactive substances naturally found in the Earth’s crust. On the other hand, some produced water may be perfectly clean, so it’s important to bear in mind that the physical and chemical properties of produced water can vary considerably depending on the geographic location of the field, the geological formation from which it comes, and the type of hydrocarbon product produced. Produced water properties and volume can even vary throughout the lifetime of a reservoir.
Options for Managing produced water
A decade ago, research by Argonne Laboratories revealed that Oklahoma produced 2,195,180,000 (11% of the U.S. total) barrels of produced water. (1 barrel of water = 42 U.S. gallons). At that time, water was routinely injected back into the subsurface for disposal or enhanced recovery purposes. In fact, 98% of the water produced onshore was injected underground. Nearly 60% of this water was injected into the producing formation to boost production, while the remaining 40% was injected into nonproducing formations as a method of disposal.
In the year of the study (2007), there was one instance of surface discharge management practice in Arkoma Basin as part of a surface reclamation project for abandoned strip mining project. During the period, there was only a single permit for recycling of produced water. Undoubtedly, produced water disposal by underground injection has been considered the safest, least expensive method of water management. The map below depicts produced water volumes by county as of 2015 when the total volume for the year in Oklahoma topped out at 3,071,783,435 barrels.
Today, that story may be changing as the cost of managing water is on the rise and alternatives to disposal by injection are being considered in the wake of increased seismicity in the state has caused tighter regulation and curtailments of injections.
According to the research firm, Bluefield Research, oil prices around the $50 mark coupled with new drilling techniques are reversing the downward trend in water management spending. Their analysis suggests that during the period of 2017-2026 U.S. operators will spend more than $136 billion on water supply, transport, storage, treatment, and disposal.
As Bluefield’s chart depicts, U.S. water management and services spending increases are forecasted to continue through the next decade with water transport, and storage costs significantly outweigh those for water sourcing, treatment, and disposal combined. Furthermore, it appears that disposal spending increases modestly, if at all, over the period while water treatment costs modestly increase. Might this signal an increase in water treatment for recycling and reuse? Groups working on Oklahoma’s Water for 2060 initiative would like to think so.
Produced Water Working Group
As part of Governor Fallin’s Water for 2060 initiative, several working groups were formed to study options for meeting the state’s goals for consuming no more fresh water in 2060 than was consumed in 2010. Among the groups formed was the Produced Water Working Group (PWWG) who studied options for reusing and recycling water produced from oil and gas operations as an alternative to the current practice of disposal. Specifically, the PWWG’s objective was to determine the potential for produced water to become the source for other beneficial uses, such industrial applications or crop irrigation. Their method was to investigate produced water sources, water quality, major water users in the state, and water treatment costs. From these inputs, a subset of likely produced water users coupled with potential water sources. These pairings were then used to evaluate the economics of produced water treatment or reuse alternatives. Their result was a prioritized list of recommendations with the most viable, near-term option being reuse of produced water by the oil and gas industry. Other options requiring further study were:
- Water transfer and reuse
- Evaporation techniques
- Water treatment and desalination
You can see a summary of their recent findings and recommendations at http://www.owrb.ok.gov/2060/PWWG/Study_2_Page_Handout.pdf
Industry water reuse and recycling
Even though most produced waters often contain drilling and fracking fluids as well as salt and other subsurface constituents, it is possible for these waters to be reused and recycled. Water treatment techniques include deoiling, desalination, degassing, suspended solids removal, organic compounds removal, heavy metal and radionuclides removal, and disinfection. These treatment options are essentially the same for potable, non-potable reuse, or disposal, although the level of contaminant removal required for potable reuse can be significantly higher, depending on the quality of the produced water. The common element among all these options is cost. With the produced water management costs now ranging anywhere from a few cents to $5 or more per barrel, profitability of projects could be threatened. As operators continue to face pressure to reduce their development and production expenses, cost will remain at the crux of the industry’s complex relationship with water.
The good news is that companies are developing more cost-effective water management options and costs for treating and reusing water are coming down. Some operators are now finding value in managing water through reuse and recycling programs and technologies. Newfield’s Barton Recycling Facility in Kingfisher County is expected to be ready for operation sometime early in the 3rd quarter of this year. Once active, the facility will recycle all the company’s water from its STACK operations. Another example is Chesapeake Energy whose strategy is to reduce its use of freshwater by prioritizing and sourcing non-potable water for its operations. The company also treats and reuses produced water in its other completion operations. Devon Energy also recycles their water and like others, are relying more on pipelines for water transfer as opposed to trucking.
As for disposal practices, injection wells, which are still the least expensive (and most common method) for disposing of produced water. But, this may not be the case much longer. Increased STACK and SCOOP operations, heightened injection well regulation due to earthquake activity, and rising demand for fresh water is driving change. New technologies and businesses are emerging that will likely threaten the status quo. More on this as our Oil and Water series continues. Until then, you can always reach out to me at email@example.com
Oklahoma Water Resources Board
EOS Data Analytics
Julie Parker has a decade of experience serving the Energy industry where she became an expert in the integration and application of geospatial technologies to exploration and production projects and workflows. Ms. Parker entered the industry in 2006 when she became the first GIS Director for Chesapeake Energy, a large independent producer of natural gas headquartered in Oklahoma City, Oklahoma with operations throughout the U.S. During her tenure at Chesapeake, Ms. Parker built and lead a robust, cross-functional GIS department that gained a reputation for developing and deploying leading edge solutions for nearly all areas of the company.