Treatment Of Flowback For Reuse: An Emerging Oilfield Practice

Water recycling is a growing practice in North American hydraulic fracturing operations. While freshwater remains the predominant fracturing fluid across the industry, an increasing number of operators are completing wells with blends of freshwater and brine water that flows back from completed and producing wells (flowback).

In some cases, direct reuse with minimal conditioning is practiced. However, most flowback requires some kind of chemical or physical treatment step to make it suitable for fracturing operations. As such, treatment technologies are usually deployed to meet one or more of three main goals: control of particulate matter, removal of deleterious components and bacterial disinfection.

Solids in flowback

Water flowing back from the formation will inevitably contain suspended, insoluble particulate matter. If suspended solids remain in recycled water, these will nurture the growth of subterranean microorganisms, cause damage to the proppant/sand pack and negatively affect permeability. To illustrate the significance, consider a fracturing operation that will use 160,000 bbl of a 1:1 flowback/freshwater blend, in which the flowback contains a seemingly small amount of suspended solids, 350 ppm. Left untreated, the blend will deliver nearly 5 tons of solids into the formation.

However, by employing technologies to reduce the level of suspended solids to 10 ppm, the amount of solids going downhole will drop to less than 600 lb. The most common approaches for managing solids are mechanical clarification techniques that include inclined plate separators, centrifuges and filters. Performance of these devices is often enhanced by the addition of supplemental chemical additives.

Other components

Depending on the shale play, flowback water under consideration for reuse can contain deleterious components like metals, acid gases and ions that will form mineral scale with counterparts in blended freshwater. Dissolved metals like iron and boron will interfere with the performance of friction reduction polymers and borate-crosslinked gel fluids, respectively. Treatment to reduce dissolved iron levels is fairly straightforward and inexpensive. It can be accomplished by converting the iron to an insoluble form by adjusting pH or adding an oxidant. The resulting insoluble material can be removed by the methods discussed above for solids management.

Removal of boron is a more difficult task. At best, boron removal technologies are only effective at treating low daily water volumes. In practice, these are generally considered inefficient and costly when used for treating oilfield flowback. Because of these limitations, blending recycled water with freshwater is the most cost-effective and reliable means for meeting frack water boron specifications.

Dissolved hydrogen sulfide (H₂S) is the most troublesome acid gas found in flowback water. H₂S arises from the growth of sulfate-reducing bacteria (SRB) in the formation. If left unchecked, H₂S can lead to equipment and wellbore corrosion. Corrosion byproducts in the form of metal sulfides subsequently precipitate and compromise formation integrity. Additionally, H₂S is a hazardous material and creates environmental and safety risks, even at part-per-million levels. H₂S can be scavenged from flowback with chemical additives. However, this can quickly become expensive. The best way to mitigate H₂S in flowback is by prevention. Many operators add conventional liquid biocides to freshwater/flowback blends at the frack pad to inhibit or slow the growth of downhole microorganisms like SRB and acid-producing bacteria. Successful control of downhole bacteria with conventional liquid biocide is mixed. This is due to a number of factors, including the short half-life of biocides downhole, the inadequate removal of solid nutrients from waters sent downhole that feed microbial growth and the incomplete sterilization of topside water used in fracturing operations.

Chlorine dioxide

One of the most rapidly growing water treatment technologies in the oil field is sterilization by the addition of chlorine dioxide gas to freshwater used in fracturing operations. The practice is borrowed from other industries where chlorine dioxide is used to sterilize drinking water. The appeal of chlorine dioxide is that it is inexpensive and fast-acting. Unlike conventional liquid biocides, chlorine dioxide is a small molecule that can easily penetrate bacterial cell walls and biofilms.

Chlorine dioxide also can be used for treating flowback. Of course, it can be used to kill incipient bacteria in flowback, but this use requires a careful understanding of the chemistry, reaction kinetics and mode of action. Unlike other industries, or even the treatment of freshwater in the oil field, the complex water composition complicates the disinfection of flowback with chlorine dioxide. If not managed properly, competing reactions can dilute or minimize the ability of chlorine dioxide to kill bacteria.

In addition to acting as a disinfectant, chlorine dioxide can be a useful oxidizer for the treatment of flowback. Unlike alternative oxidizers like bleach and hydrogen peroxide, chlorine dioxide is a selective oxidizer. This property can be leveraged intelligently to meet other flowback treatment goals like the removal of metals and acid gases.

A key component to a comprehensive program for treating flowback and blends with freshwater is process monitoring, not just around treatment units but at the blender as well. When implemented properly, a chlorine dioxide treatment program has the potential to reliably deliver sterile, high-quality water to the blender.

When considering a program to reuse flowback water for hydraulic fracturing operations, there are a number of factors that should be considered. Foremost, operators should assess treatment goals. This will largely be driven by water quality need.

The level of treatment needed to meet water quality specifications will have a significant impact on price. For example, if distillate quality water is needed, minimum treatment costs will be around $4/bbl. Another factor that has a significant impact on cost is available flowback volume. While there are some exceptions, generally it is hard to treat flowback for less than $1/bbl unless daily water volumes exceed 10,000 bbl/d. Depending on the technology and treatment goals, costs can drop dramatically as volumes approach 25,000 bbl/d. At these volumes, it is not unusual to see costs for treating flowback drop to less than $0.40/bbl. Finally, another critical factor to evaluate when considering a reuse program is the location and availability of existing infrastructure (infield transfer lines, injection wells and impoundments) in support of treatment and reuse activities.

Water reuse by oil and gas operators is becoming more prevalent in North America. Drivers vary by region and shale play. For some, the high cost to dispose of flowback is driving reuse; for others, the limited availability of freshwater is justifying investment in recycling. However, no matter which driver is affecting need, the industry is increasingly turning to available, cost-effective treatment technologies for treating flowback.