Flaring alternative acts as portable produced-water management tool

Gas flaring has been utilized in oil exploration and production for decades. Flaring, in this context, is the controlled burning of wellhead gas. Typically, flaring is temporary, while the gas is tested to determine pressure, flow and composition. In addition to testing, there is also the time that it takes to connect the gas flow to a collection system. 

Flaring is not a new practice. The U.S. Energy Information Administration (EIA) has flaring data all the way back to 1936. In 2014, the EIA reported that one third of all natural gas produced in North Dakota was flared. EIA further reported that 210.554 Bcfg were vented or flared in 2016, with Texas leading other states at 87.527 Bcf. The shale boom has brought new attention to the practice of flaring. The most common concerns are noise, visual impact and wasted resources. In North Dakota, there also have been civil suits filed by landowners that claim lost royalties. The reality is that there are practical limitations to collecting gas at every well, and for safety reasons, flaring is a reasonable remedy.

Unfortunately, the public perceives that flaring is widespread, and that it is happening more frequently than it actually is. A quick look at Texas shows that in 2016, the Railroad Commission (RRC) issued 4,870 venting and flaring permits. These permits are temporary in a state with more than 311,000 active wells in 2016. So, flaring takes place at a small percentage of wells, and the RRC issues these permits in 45-day intervals, with a maximum limit of 180 days.

Nonetheless, in April 2012, the U.S. Environmental Protection Agency (EPA) issued federal rules targeting emissions from unconventional oil exploration and production, including flaring. The EPA referred to these rules as reduced emission completions or “green completions.” The effective date of these rules was January 2015. Although the EPA limited flaring under these rules, which was already being limited by most states, the agency allowed for alternate uses of wellhead gas. These regulations can be found in EPA Chapter 40 of the Code of Federal Regulations (CFR), Part 60, Subpart OOOO section (a), also referred to as Quad O (a). 

Fig. 1. The HydroFlare utilizes an enclosed waste fuel combustor, with an attached wet scrubbing tower that serves as a combination scrubber and evaporation chamber.

In 2016, these rules were amended for expanded scope, but under the current U.S. administration, the amendments were reviewed and ultimately stayed, bringing many to speculate on what may happen to Quad O (a) in the future. In the meantime, Quad O (a) is a reality, and the alternative use allowance has caused operators to look at alternate strategies to address wellhead gas from unconventional oil wells.

The review of substitutes for flaring wellhead gas led to the development of HydroFlare, a patent-pending design that replaces traditional flaring, addressing its common concerns—noise, visual impact and waste of a natural resource, Fig 1. The design utilizes an enclosed waste fuel combustor, with an attached wet scrubbing tower, that serves as a combination scrubber and evaporation chamber. The enclosed combustor reduces noise, while the waste fuel burner accounts for the variable BTU value in wellhead gas. Because wellhead gas is not consistent in quality, and a standard burner can have trouble with varying BTU value, a waste fuel burner is designed to manage a variable BTU value fuel source. The insulated chamber retains heat, while also reducing noise. Insulating the combustor also allows for less heat loss and better evaporation efficiency.

Fig. 2. Demisting improves evaporation efficiency and removes evaporated solids via an auger discharge system.

The hot air exits the combustor and enters a wet scrubbing chamber. In this application, the wet scrubbing chamber also serves as an evaporation chamber. The produced water enters near the top of the chamber and is sprayed into the chamber through a series of non-clogging spray nozzles. A demister section allows for a fine mist in the stack exhaust, while supplying backpressure to the chamber and increasing retention time of the combustor air. This increased retention time improves evaporation efficiency, with the use of a demister. Evaporated solids also are removed continuously via an auger discharge system, Fig 2.

Demisters are often overlooked, but without them, larger water droplets can form, which can ultimately create a raindrop effect, leaving a water trail on the floor surrounding the evaporation system. With a demister, water droplets remain small, which allows them to evaporate outside of the stack and keeps water from dropping to the floor. This may seem inconsequential, but, from slip-and-fall hazards due to a wet floor, to compliance concerns over produced water leaks, the consequences can be burdensome.

OKLAHOMA AND INDUCED SEISMICITY

Oklahoma has had its share of earthquakes that have been tied to the injection of produced water into salt water disposal wells (SWDs). It has been implied that high concentrations of SWDs have been a potential source of induced seismicity. Induced seismicity is basically the influencing of seismic activity through some cause-and-effect scenario. In this case, the cause and effect are not well understood, but there is a correlation between SWD density and seismic activity, leading to the conclusion that SWDs could be a potential cause of induced seismicity.

Oklahoma has closed many SWDs to reduce the density of the disposal wells, and to try to alleviate induced seismicity concerns. This creates areas of unconventional activity, where produced water may have to travel further distances, via truck, increasing the cost of disposal of produced water. In most cases, reusing produced water as a completion fluid is the most cost-effective option, but well completion schedules and locations don’t always cooperate with the constant flow of produced water from producing wells. Concerns over induced seismicity limit SWDs, and the time and cost to drill new SWDs in areas with less density only increases the cost of produced water management.

This is an instance when a portable system that provides produced-water disposal capacity can be an extremely useful tool. HydroFlare is not just an alternative to the conventional flare—it also is a portable produced water management tool, providing produced water disposal capacity when, and where, it is needed. Producing wells, located away from well completion areas, are not good candidates for reuse, as the logistics of collecting and transferring the produced water can be costly. 

Now, the operator has the capability to use a device that can move to those remote wells, use wellhead gas and either fully evaporate or volume-reduce the amount of produced water needing disposal. As activity moves, new areas of remote wells can develop, but now a portable device can move from location to location, and can get instant capacity where it is needed.

HELD BY PRODUCTION (HBP) WELLS

HBP wells are required, when an operator is obligated by a landowner to maintain a lease, in order to have some level of production on the land. In many cases, these are single wells drilled to hold the lease, but usually, there is no surrounding infrastructure, leaving most of these HBP wells stranded. The portable produced water management tool can be a valuable tool in this instance, because it provides capacity for the wellhead gas, as well as the produced water.

THE UTICA AND INDUCED SEISMICITY

Oklahoma isn’t the only area concerned with induced seismicity. In Ohio, limits to SWD density are already in place, and seismic monitoring is required on new SWDs. Not only does this increase the overall cost of the SWD, there have been cases where new SWDs set off seismic monitoring during their first days of operation, ultimately causing permits to be denied. In this environment, permitting and constructing an SWD does not provide certainty that it can be operated. This not only affects Ohio, but the neighboring Marcellus that sends some produced water to Ohio. Again, a portable, produced water management system is needed.

THE CASE FOR THE MARCELLUS

Essentially, the Marcellus is a pure gas play, so flaring has temporary viability, if it is used at all. Produced water in the Marcellus is mostly recycled, and that is the best reuse of produced water, although natural gas supply and demand can cause oversupply issues, ultimately impacting completion schedules. Mild weather also can reduce natural gas demand and drive up supply, causing a reduction in market price for natural gas. As natural gas prices fall, completion activity drops, leaving the need to manage all the produced water that can no longer be used as a completion fluid. Disposal costs for produced water are higher in the Marcellus than in other parts of the country, so the need for temporary capacity when gas market prices drop becomes critical. A portable evaporator that can work off of field gas can address this issue.

WHAT ABOUT THE PERMIAN?

Just like the other plays mentioned, the Permian basin has many of the same issues—HBP wells, rapid activity where infrastructure can’t keep up with completion activity, etc. This always leaves some degree of stranded wells that are waiting for infrastructure to catch up. During this period—when infrastructure is lagging—disposal options involve trucking and commercial SWDs, and higher costs. Trucking and commercial SWDs can be reliable options, but with so many operators in the same areas, stress is created on the commercial disposal network and, as a result, a spike in commercial SWD prices can be caused. With reliable capacity, a portable evaporator can give the operator some control over these situations.

Fig. 3. The HydroFlare is undergoing emissions testing in the Permian basin.

FLOWBACK PERIOD AFTER COMPLETION

Once a well is completed, the flowback period is started when some of the completion fluid is recovered, and before the well is brought into production. During this period, wellhead gas is typically flared, and flowback is taken for disposal. Flowback water resembles completion fluid, but because of the chemical additives used in the completion fluid, it is usually more costly to dispose of. HydroFlare is a reliable tool for managing flowback, as well. Since the operator is likely flaring gas during this period, the company can use an enclosed combustion device, reduce noise and visibility, and evaporate flowback.

WHAT’S NEXT?

The new tool is in the Permian basin, undergoing emissions testing, Fig. 3. Hydrozonix expects to release results in fourth-quarter 2017. The company will be determining what kind of emissions reduction is achieved by using produced water as a scrubbing fluid to reduce SOx, particulate matter and acid gases, as compared to using no control measures. The system is not just an alternative to a conventional flare system, but a flexible, portable produced-water evaporator that can provide temporary relief to stressed produced-water disposal capacity issues, whether there from supply and demand, induced seismicity, or a lag in infrastructure development.  

About the Authors

Mark Patton

Hydrozonix

Mark Patton is president of Hydrozonix and has more than 30 years of experience developing water and waste treatment systems for the oil and gas industry. This includes design, permitting and operation of commercial and private treatment systems, both nationally and internationally. He has seven produced water patents and two patents pending. He earned his B.S. in chemical engineering from the University of Southern California (USC) in 1985.