When Water Becomes Waste
Production water releases from fracking operations require a coordinated response.
The rise in hydraulic fracturing and horizontal drilling in the oil and gas industry has dramatically increased not only the supply of domestic oil and natural gas, but also related waste products. This has led to a significant growth in claims relating to the release of water extracted from the ground as a byproduct of oil and gas production.
Between 2000 and 2014, the median volume of water used to drill and complete a horizontal natural gas well increased from 177,000 gallons to 5.1 million gallons. All told, between 2012 and 2014, hydraulic fracturing consumed around 48 billion gallons of water per year.
This has contributed to the annual volume of up to 30 billion barrels of water generated in the U.S. by oil and gas production that requires reuse, treatment, or disposal. From August 2013 to August 2014, there were more than 800 production water releases, totaling nearly three million gallons, in the state of North Dakota alone, according to an Inside Energy analysis.
Following a release, the brine in the water can cause soil dispersion, vegetation kills, groundwater contamination, and surface water contamination. Due to the frequency of releases and the associated costs, it is important for claims analysts and environmental counsel to understand potential risks, identify and hire the right people to address them, and cost-effectively remediate sites as necessary.
Water produced from a well has as its source formation water, flowback water, or a mixture of the two. Formation water is naturally present, and is called production water when it is extracted along with oil and/or gas. Formation water, which may be a disposal issue even if the well was not hydraulically fractured, often contains large amount of salts and particulates (such as chlorides) that can range anywhere from 5,000 mg/L to 400,000 mg/L. The levels depend on the geographic region and the geologic formation. Formation water also usually contains smaller amounts of metals, hydrocarbons (including BTEX), and naturally occurring radioactive materials, or NORMs (radium, radon, uranium).
Flowback water, on the other hand, comes back out of the well after being injected for the purpose of hydraulically fracturing the hydrocarbon-bearing formation. Flowback water contains the constituents that were added to the water to perform the frack job. These additives, which include proppants (such as sand or ceramic beads) and often proprietary chemical lubricants, biocides, and scale inhibitors, usually make up around one percent of the volume of the injected water. Given the quantity of water used, these non-water additives could total 50,000 gallons or more at a single well.
Initially, a fracked well will primarily produce flowback water, and the ratio of production water to flowback water will increase over time. For ease of reference, we will use the term production water to mean both formation water and flowback water.
Whether it will be treated, stored, or disposed through injection, production water almost always requires transportation from the wellsite. This is usually done by trucks, but it also can occur by pipeline or train. These transportation modes, as well as their points of transfer, are potential sources of releases.
Production water releases often are viewed and managed similarly to oil and gas releases. Like hydrocarbon releases, they primarily occur at the wellhead or in transport, either via pipeline, truck, or train. Production water releases are different from hydrocarbon releases, however, in terms of how they can be assessed and remediated.
Less experienced consultants or emergency responders may use a one-size-fits-all approach to remediation: delineate, excavate, transport, and dispose. But this can be expensive. Hiring experienced coordinating environmental counsel, who can then recommend and work in concert with specialized consultants early during a release, can help claims close faster and with fewer expenses.
Companies should consider retaining a soil scientist who understands how to remediate soils affected by salts. Many U.S. regions have soils with naturally high salinity and it may be advisable for a consultant to compare any potentially affected area to a “background” sample from an unaffected area.
In addition to excavation, consultants also may be able to remediate sites affected by production water through in situ remediation, particularly if the impacted area is not too deep. In some circumstances, the use of soil amendments, such as gypsum, lime, or calcium chloride, may assist in removing salts.
Closure requirements and remediation standards vary from state to state, and local regulations must be considered when assessing remediation options. In North Dakota, for example, the Department of Health uses unpublished guidance of 1.5 millimhos per centimeter for electrical conductivity and 250 ppm for sodium, among other criteria, above which the department recommends further remediation action (there is a different regulatory agency and remediation standard for releases on an active well pad). As with any response action, remediating a production water release requires performing the work necessary to protect human health and the environment, and obtaining closure without significant cost and residual risk.
Insurance carriers need to be aware that adverse contractual terms and conditions in a policyholder—contractor/consultant professional services agreement (PSA) may drive costs higher. Carriers can mitigate this exposure by establishing early-response protocols at the onset of policy acquisition. These protocols can include notifying coordinating counsel of the loss that will trigger an emergency response team made up of pre-vetted professionals to handle the remediation efforts.
In instances where the policyholder has signed a PSA without experienced counsel, we often recommend that the policyholder replace the emergency response teams as soon as the release is contained. The policyholder then can contract with preferred vendors under terms that are more beneficial than the typical “boilerplate” language used by consultants. This has the added benefit of allowing the work to proceed under an approved budget, with a work plan that is vetted by the claims professional and environmental counsel. We believe this process helps control financial risk. In addition, the coordinating team can assist in acting as a common point of contact, potentially preventing employees from giving inaccurate information or making adverse statements without appropriate guidance.
Another issue that may arise is access to private property, which might best be done under a site-access agreement. The location of the release is critical, particularly if it is to “Waters of the U.S.” Environmental counsel can assist in assessing whether the release is to a WOTUS and advise the policyholder on a recommended course of conduct.
Releases of production water present unique problems. A coordinated strategy can help identify cost effective remedial options and properly navigate a claim to closure.