Water-Energy Nexus: Common Misconceptions about 'Produced Water' in Oil and Gas Production
In a recent report titled “Produced Water: Asset or Waste?” – part of the Atlantic Council’s Energy and Water Nexus Initiative series – Blythe Lyons, Nonresident Senior Fellow (Energy and Environment Program), addresses water-related issues – in particular the treatment of ‘produced water’- in US oil and gas production as well as concomitant sustainable water strategies.
‘Produced water’-related costs are a major factor in the oil and gas production. The report feeds off a workshop held at the Atlantic Council in June 2013 and summarizes key insights gained from the workshop discussions. It arrives at the fundamental conclusion that despite the fact that ‘produced water’ is still regarded as a pollutant and, therefore, seems logically detrimental to environmental security, “if managed appropriately, it could be recycled and utilized as an asset and new resource in the energy industry.”
The US Department of the Interior defines ‘produced water’ as follows:
“’Produced water’ is defined as the water that exists in subsurface formations and is brought to the surface during oil and gas production. Water is generated from conventional oil and gas production, as well as the production of unconventional sources such as coal bed methane, tight sands, and gas shale. The concentration of constituents and the volume of produced water differ dramatically depending on the type and location of the petroleum product. ‘Produced water’ accounts for the largest waste stream volume associated with oil and gas production.”
Another more specific version of the EPA definition is:
“‘Produced Water’ means the water (brine) brought up from the hydrocarbon bearing formation strata during the extraction of oil and gas, and can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process.”
In this context, the first misconception occurs. In the public discourse the nuanced terms ‘flow back water’ and ‘produced water’ are frequently misused. Blythe Lyons attributes this to the fact that some mistake a water type for “a process in which the hydraulic fracturing fluids, containing water, return to the surface.” She draws a nice distinction by stating: “In summary, flow back water can be thought of as water returning to the surface over the first few days to weeks after the well starts producing and then what follows is the long-term flow of produced water.”
The second misconception is directly tied to the first one. Ms. Lyons points out that contrary to popular belief “less than 6 percent of produced water is related to shale gas. (…) Conventional oil and gas wells produce large volumes of produced water over their lifetimes [while unconventional] gas play wells provide relatively little amounts of produced water.”
John Veil of Veil Environmental (LLC) made this point very clearly during his presentation at the Atlantic Council event. The following graphic illustrates that while conventional oil and gas production generates initially a relatively low flow volume of ‘produced water’, which increases over time, the lifetime ‘produced water’ generation is high. In contrast, even though unconventional shale gas production may record an initially high ‘produced water’ flow rate, this rate tends to drop quickly and significantly reaching a very low base. Consequently, shale gas production has low lifetime flow back and ‘produced water’ generation.
‘Produced Water’ Volume Changes Over Time in a Well/Field
The reason why the required water volumes during the shale gas production process get so much public attention is the fact that the focus is entirely on the relatively large water needs for production – for the hydraulic fracturing process. The following ‘infographic’ seems to illustrate this point well.
The Water-Energy Nexus
Source: GE Look ahead
This, however, is the wrong comparison. Instead, shale gas water needs to be set in relation to all ‘produced water’ generation. In this respect, Mr. Veil makes another very important point; namely, that “there is a lot of produced water generated each year from hundreds of thousands of oil and gas wells. Management of that water must be practical and comply with regulations. Most of the produced water is injected – 60 per cent for enhanced [oil] recovery, 40 per cent for disposal.”
REV H2O, a diversified fluids services and management company, seconds this statement and adds that “wells may start out producing little water but sooner or later all oil wells produce a much larger volume of [most likely saline] water than oil.” Given the obvious cost component in order to remain in compliance with regulations due to legitimate public environmental security concerns, “the ability to efficiently and economically dispose of this water is critical to the success in the oil production business,” REV H2O notes further. According to REV H2O, and in line with projections in the Atlantic Council report, the US is estimated to produce 882 billion gallons of ‘produced water’ onshore annually. This sheer amount of water demands not only practical, cost-efficient as well as sustainable water strategies on the part of energy companies – e.g. reuse of water in adjacent oil and gas production fields/wells – but also adequate, environmentally-sensible treatment before water disposal. The following chart gives an overview of ‘produced water’ treatment approaches across different US shale plays.
Produced Water Treatment Approaches Across Different US Shale Plays
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Roman Kilisek is a Global Energy & Natural Resources Analyst and a contributor at Breaking Energy. His writing and research focuses on global energy policy, energy infrastructure and trade, commodities, mining, global political risk and macroeconomics. He likes to draw on scenario development and analysis. He has a Master of Arts degree in international relations and diplomacy from Seton Hall ...
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