Saltwater Disposal Facilities

1 INTRODUCTION

1.1 Saltwater Disposal Overview

Oil and gas production methods generate “saltwater,” which is considered hazardous waste because of its high salt content, hydrocarbons, and synthetic additives. “Produced” water is saline pore water that is coproduced with oil and then injected into deeper sedimentary formations. Hydraulic fracturing of shale gas wells creates millions of litres of this saltwater, also called “produced water” or “oilfield brine.” The water delivers oil and gas to the surface, where impurities are removed by chemical methods, resulting in a liquid by-product that must then be safely discarded.

Field operators can recycle the water, injecting it back into working reservoirs for reuse in collecting any remaining hydrocarbon, or they can dump it at a saltwater well. Because of the potential for small earthquakes and groundwater contamination, the placement of these high-pressure disposal sites can be controversial.

The US Environmental Protection Agency (EPA) defines an injection well [1] as “a bored, drilled, or driven shaft whose depth is greater than the largest surface dimension; or, a dug hole whose depth is greater than the largest surface dimension; or, an improved sinkhole; or, a subsurface fluid distribution system.” Saltwater disposal wells, widely used since the 1930s, confine the water so it cannot contaminate land or water resources. Most produced water was initially dumped in surface water. Since the 1950s, it has been stored in deeper wells. They are barriers made to protect the environment from the effects of oil and gas extraction, and each jurisdiction also has its own legislation regarding saltwater disposal wells.

1.2 How Does Traditional SWD Work?

Saltwater is commonly ejected from the wells into natural underground formations sealed within a thick impermeable rock to prevent the solution from escaping into surrounding soil and groundwater. These formations are typically deep beneath the surface soil layer and consist of limestone or sandstone. Environmental protection authorities keep a close eye on these saltwater well disposal sites, and it is not an easy job. For instance, in Texas alone, more than 50,000 well sites occur.

Protection of surface water and groundwater is becoming a critical consideration in the oil and gas energy sector. Site operators essentially have four choices for management of on-site wastewater streams: collect the water and transport it to commercial waste management facilities or saltwater disposal wells, collect the water and transport it to a publicly-owned treatment works, collect the water and treat it on-site and discharge the effluent vis-à-vis a discharge permit, or collect the water and treat it for recycling/reuse.

Figure 1. Tanks at an SWD facility in Orla, Texas. Source: https://www.withrossgroup.com/saltwaterdisposalfacility

The USEPA requires that wells projected to dispose of hazardous wastes be constructed of as many as three layers. To safeguard the groundwater in the area, the first outer layer penetrates as far into the ground as necessary. It’s typically built of steel pipe and cement. Another layer shields the entire well, and a third covers the injection device. Because there are three barriers in place, each one must be broken before the nearby groundwater can become contaminated. The EPA labels all saltwater disposal wells into six classes based on their structure and operating features.

• Class I: Inject hazardous wastes, industrial non-hazardous liquids, or municipal wastewater beneath the lowermost underground source of drinking water (USDW);
• Class II: Inject brines and other fluids associated with oil and gas production and hydrocarbons for storage;
• Class III: Inject fluids associated with solution mining of minerals beneath the lowermost USDW.
• Class IV: Inject hazardous or radioactive wastes into or above USDWs.
• Class V: All injection wells not included in Classes I-IV.
• Class VI: Inject carbon dioxide (CO2) for long-term storage, also known as Geologic Sequestration of CO2.

2 RISKS AND CHALLENGES

2.1 Saltwater Regulations in the US

States and tribal administrations can make “primacy” requests or sue the right and responsibility to impose regulations within their jurisdictions if they meet federal Underground Injection Control (UIC) requirements. As of June 2022, 32 states and three territories have endowed primacy. The EPA regulates saltwater disposal wells through its regional offices in 10 other states and for most tribes, as well as the District of Columbia and two US territories. It shares responsibility for enforcement with local agencies in seven states.

EPA may grant primacy for all or part of the UIC programme; in other words, in some jurisdictions, priority for specific well classes may be shared with EPA or divided between two different states, territories, or tribal authorities. EPA approved UIC primacy programs for well classes I, II, III, IV, and V in 32 states and three territories. Two states have primacy for well classes I, III, IV, and V and two states have primacy for Class VI. Additionally, there are seven states and two tribes that have preference for Class II wells only. North Dakota and Wyoming are the only states with primary enforcement authority for UIC Class VI wells. EPA now implements the Class VI program in all other states, territories, and Indian countries [2]. The Safe Water Drinking Act, passed in 1974, requires that the EPA maintain minimal federal requirements for the practice of saltwater disposal and regularly report on them to Congress.

EPA’s general activities consist of the following:

1. Concentrate UIC compliance and enforcement efforts on suspected violations that may threaten or contaminate underground drinking water sources as well as those that represent the most significant hazard to public health.
2. Utilise the 1987 UIC Program Compliance Strategy for Primacy and Direct Implementation Jurisdictions, or a pertinent regional enforcement strategy, to the extent practicable.
3. Directly implement the program pursuant to SDWA and its implementing regulations.
4. Conduct inspections to identify and resolve noncompliance and deter future noncompliance.
5. Initiate enforcement actions pursuant to SDWA section 1423 to resolve alleged violations, where appropriate.
6. Utilise SDWA section 1431 to abate imminent and substantial endangerments to public health stemming from contamination by UIC wells, where appropriate.
7. Oversee primacy programs to assess the effectiveness of UIC programs.
8. Initiate enforcement actions pursuant to SDWA section 1423 to resolve alleged violations, where appropriate.
9. Utilise SDWA section 1431 to abate imminent and substantial endangerments to public health stemming from contamination by UIC wells, where appropriate.
10. Report data to ICIS and the UIC Data Application per programmatic deadlines.

2.2 Water Volumes

The effect that both conventional oil and gas and hydraulic fracturing industry has had on water resources may affect contaminant transport into near-surface environments. Large volumes of water are injected for secondary and tertiary recovery, collectively referred to as enhanced oil recovery (EOR), and management of produced waters via SWD. Injection of water for EOR has occurred since 1880 [3]. Possible impacts to groundwater systems from EOR were noted in the 1980s, notably through leaky wells (Figure 2). Well integrity issues, such as faulty well casings, poorly cemented well annuli, or abandoned or legacy wells, have been identified as likely pathways for fugitive methane migration into shallow aquifers related to fracking. The conventional oil and gas industry shares these same well integrity issues.

Figure 2. Conceptual model of water cycling in a sedimentary basin due to conventional and unconventional oil production and saltwater disposal. Source: https://doi.org/10.1002/9781119099987.ch5

Several studies recognised that the volumes of water involved with conventional oil production are large compared to those associated with hydraulic fracturing, suggesting that impacts to groundwater from EOR and SWD might be more likely than fracking. Large volumes of water are injected into both conventional oil reservoirs for EOR and non-productive reservoirs for SWD in the United States at over 180,000 wells [4].

While the bulk of this water (∼70%) is produced water associated with oil production, which is often saline, additional fresh or brackish water (makeup water; ∼30%) is added from surface and shallow groundwater resources to make up for the volume of produced oil and gas, and maintain formation pressures for EOR. Consumptive water use for conventional or unconventional oil and gas production may reduce public water supplies and riparian ecosystem services, particularly in water-stressed regions such as California, New Mexico, and Texas.

The volume of produced and injected water, changes to subsurface pressure regimes, and potential contamination pathways of conventional oil production through hydraulic fracturing, EOR, and SWD are powerful primers for developing advanced SWD facilities.

2.3 Earthquakes and Saltwater Disposal

Over the past years, parts of the oil-producing spots worldwide have experienced noticeable increases in the number of minor- to moderate-sized earthquakes. In some areas that encompass the vast majority of the recent seismicity, increases in seismicity follow 5- to 10-fold rises in the rates of saltwater disposal. Adjacent areas where there has been comparatively little saltwater disposal have had pretty few recent earthquakes.

In the areas of seismic activity, saltwater disposal principally comes from “produced” water. Injected formations appear to be in a hydraulic continuum with potentially active faults in the crystalline basement, where nearly all the earthquakes occur. Although most of the recent trembling has posed little danger to the public, the chance of triggering harmful activity on potentially active basement faults cannot be discounted.

The number of small- to moderate-sized earthquakes in many parts of the globe began to increase markedly in the last decade. As noted by several authors [5], some of this seismicity appears to be associated with the proliferation of saltwater disposal that originates as “flow-back” water after multistage hydraulic fracturing operations.

The fact that increased pore pressure at depth occurring with fluid injection can trigger slip on preexisting, already-stressed faults is well known, and the mechanisms by which triggered fault slip occurs are generally well documented (National Research Council. (2013). Induced seismicity potential in energy technologies. National Academies Press.). Simply put, augmented fluid pressure decreases the effective normal stress on a fault. By operating perpendicular to the fault and essentially clamping it, the effective normal stress prevents fault sliding.

Because an upsurge in pore pressure reduces the effective normal stress, it acts to unlock a fault, potentially triggering the release of accumulated strain energy on a preexisting discontinuity that is already close to failure. Such faults are often referred to as critically stressed formations. When, on a critically stressed fault caused by fluid injection, a relatively small perturbation triggers the release of stored energy, we refer to it as a triggered earthquake. Strain energy (or stress) on a fault hoards over time as a natural geologic process. The pressure change resulting from fluid injection only triggers its discharge.

3 SALTWATER DISPOSAL FACILITIES

3.1 SWD Alternatives

Simply put, there are few alternatives to saltwater treatment and disposal. Contaminated waste streams must be managed, one way or another. Yet, site owners and operators do have a choice – they can decide to simply collect produced waters and transport them off-site for commercial disposal. Or, they can re-configure on-site wastewater treatment systems to accommodate more recycling/reuse of water, sometimes to the economic betterment of site operations.

In a saltwater disposal facility, frac trucks deliver fracking flowback and saltwater from the field, which is fed into a disposal well through a treatment plant. The wastewater unloaded from the truck immediately goes into a gun barrel separator (battery), where water and remaining oil are naturally separated. Additional heavy oil downstream in the facility is eventually fed back into the gun barrel separator, creating a dynamic emulsion layer. It is imperative that the oil is separated from the saltwater prior to injection into the spent well.

SWD Wells Solutions

The use of disposal wells is a primary alternative method of managing oil and gas field production and hydraulic fracturing waters. Such systems consist of engineered subsurface wells that inject wastewater under high pressure into geological formations that are located thousands of feet below the ground surface. Prior to injection, the wastewater may be partially treated, primarily to prevent or reduce fouling of the geologic formation or the well itself [6]. This could include primary filtration and some level of physical and/or chemical treatment.

There are hundreds of thousands of permitted injection wells for the injection of fluids from O&G operations. The vast majority are deemed feasible in view of acceptable geologic formations and favourable regulatory climates for large oil and gas industries in those sites. Disposal wells generally provide a low-cost solution to the management of large volumes of produced water, frack water, and other wastewaters. The wastewaters shipped to saltwater disposal facilities typically require only minimal pre-treatment to minimise down-hole fouling, either at the oil and gas field site or at the disposal company site. For owners and operators, simply “trucking away the waste” is a simple solution, similar to having one’s trash picked up.

Figure 3. Oil and gas wells near the unused well that spewed brine wastewater in Noble County, Ohio. The blue dots show the injection wells which are used to dispose of fracking wastewater. Source: https://www.fractracker.org/

A primary disadvantage of the use of saltwater disposal wells is the extensive transportation infrastructure that must exist to transport the water from the oil and gas field to the disposal well site. A typical truck capacity is about 22 cubic meters; thus, significant truck traffic results from having to transport huge volumes of water across public roads. If saltwater disposal wells are located near the oil and gas operation, transportation costs are minimal, and saltwater disposal wells offer the owner and operator a greatly simplified and economical solution. However, if the wells are distant, high transportation costs increase the overall cost considerably.

Ponding and Land Disposal

Ponding involves on-site storage of produced waters in either lined or unlined ponds or storage tanks. Except for thermal desalination treatment techniques in arid environments where evaporation exceeds precipitation, this is a temporary solution. Ultimately, any form of water storage will require treatment and/or disposal. In general, simple ponding without pre-treatment of the pond liquids presents a potential financial risk to the operator in the event of a release.

Land disposal of wastewaters produced by oil and gas operations is limited by regulatory considerations. Currently, only a handful of national and subnational administrations allow such practice. While many experts believe that land disposal is a viable solution, others do not. As a result of decades of regulations, the general trend has been away from land disposal toward other alternatives. Still, land disposal may present solutions at many sites.

Scientists have evaluated the potential influence of the land application of flowback water on the soil and, in some instances, have concluded that the ultimate feasibility of land-based disposal can be highly detrimental to water quality and poses a potentially serious human health concern. However, if toxic metals are removed via pre-treatment, then the remaining salinity could be managed through land application [7].

Treatment for Recycle/Reuse

Depending on the end use, recycling/reuse could require the removal of hydrocarbons, total suspended solids, heavy metals, friction reducers, polymer additives, inorganic scale forming compounds, and microorganisms. The treatment regimen and endpoint are a function of site-specific influent conditions and technical requirements. Whereas removing petroleum hydrocarbons, TSS, and metals is relatively straightforward, information concerning the remaining parameters may be confidential to the site operator. It must be shared in order to design a successful treatment process. Reuse by the same operator is widespread, but operators may be reluctant to accept recycled wastewater from another operator.

Moreover, a review of the contaminants in oil and gas field wastewaters leads one quickly to conclude that there is inherent value in many of the waste streams. Many hydraulic flowback and produced waters contain 0.1 – 2.0% hydrocarbons, a valuable commodity. For example, a 10,000 bbl/day treatment facility that accepts wastewater containing 1% hydrocarbons can recover 100 bbl/day of oil. At $100/bbl, this equates to $10,000/day, or $3,650,000/year.

Other wastewaters contain large concentrations of salinity, which can be processed into clean, heavy brines for reuse or salt for transportation or other uses. The generation of brines and salts may represent the cost of operation, or they may result in a net monetary credit if they can be sold. In some instances, even individual compounds may be sufficiently concentrated to encourage processing and recovery for reuse.

3.2 SWD Facility Layout

In essence, the SWD process consists of i) removing the solids, ii) separating the residual oil and as much as it can attain, iii) disposing of the remainder wastewater volume, and iv) selling away the skimmed oil. A facility hosts a number of piping, tanks, and pumps, and it is often unmanned. In general, it has none, or minimal, moving parts, and it is designed for a set of conditions, i.e., flow rate, oil concentration, oil gravity, pH, solids content, etc.

Without being intricately technical, the following figure depicts the main areas of an SWD site.

Figure 4. A conventional SWD facility. Source: https://riskengineers.com/swd-process/

This common structure has various modifications, but all SWD sites follow the same operational principles. At the end of a pipeline feed, certain facilities may have a breakout or free-water knockout tank. The process goes roughly like this:

1. Water drops in through pipeline gathering systems and tank trucks. A large-diameter conduit can gather water from multiple wells along its path. Increasingly, inactive oil and gas pipelines are being repurposed to transport wastewater [8]. Trucks, on the other hand, are more commonly employed to collect flowback water from new wells.
2. The offload pumps transfer the water that is trucked into the facility.
3. The documentation for truck drivers is handled by the ticket office. Many sites have this process completely automated.
4. The first stage removes the solids in a “desander” tank. This stops the accumulation of more solids downstream.
5. Water is then taken to a vertical gunbarrel to separate the oil from it. A gunbarrel’s typical capacity is in the range of 750-1,000 barrels, and it can process up to 10,000 barrels per day. At that rate, water is retained in the tank for a couple of hours -residence time-allowing the oil to separate through gravity and be later skimmed.
6. The treated wastewater without oil is stored in retention tanks, waiting to be injected downhole.
7. The catwalk is used for the very few instances when people are at the facility inspecting or maintaining the tanks.
8. The injection pumps draw water from the water holding tanks and inject it downhole through a saltwater disposal well.
9. The skimmed oil is stored until being recirculated/sold and periodically taken away with an oil tanker.

3.3 Separation Cost and By-products

Any unit downstream from the gun barrel separator must effectively separate oil from water. In the event that oil spills over into the disposal well, it may clog or damage the well, necessitating additional labour and delay, as well as raising the cost of the chemicals used in the treatment process.

Having a sharper understanding of the day-to-day storage needs of “unwanted” liquids in the tank battery (pending disposal) versus production capacity enables improved resource management and usage, such as trucks getting dispatched to remote sites in due time and with sufficient capacity. The separated oil provides the business with additional money on top of the saltwater disposal cost. The injection well’s capacity is eventually limited by any remaining oil in the seawater because of its porous nature, necessitating costly well reworking.

While the top layer of oil is sent to a separate holding tank, the oil-water emulsion is passed into a treatment unit just after the gun barrel separator. Thanks to recent developments, guided wave radars (GWR) transmitters effectively measure the hydrocarbon level in the gun barrel tank and the top of the oil-water emulsion, making sure that the different products are routed to the appropriate compartments. This, in turn, prevents potential downstream plugging of the disposal well and lowers chemical treatment costs. Additional GWR transmitters or non-contact radar devices can then be utilised for the standard total level measurements.

3.4 Hauling Optimisation

Saltwater disposal is significant traffic generating activity in both unconventional and mature oil and gas fields. In unconventional reservoirs, hydraulically fractured horizontal wellbores produced substantial volumes of flowback water early in their productive life. This water is collected from production facilities located throughout the field and either hauled or pipelined to saltwater disposal facilities. In mature oilfields, produced water is injected to maintain reservoir pressure and improve sweep efficiencies in either secondary recovery (waterflooding) or enhanced oil recovery (especially CO2- EOR) operations.

Produced water volumes in CO2-EOR projects are typically greater than injected volumes; excess water should be properly disposed of in wellbores located in either non-productive reservoir regions/formations or commercial saltwater disposal facilities. While significant volumes of produced water are reinjected/recycled in secondary/tertiary recovery projects, the E&P industry still transports substantial volumes of produced water across oilfield areas roadways to commercial saltwater disposal facilities.

Disposal of produced/flowback water can also represent a substantial portion of the lifetime operating expenses incurred by oil and gas assets; minimising this expense can result in significant capital savings. Disposal expenses can be minimised through the minimisation of disposal hauling distance and driver standby charges. In a review of commercial saltwater disposal fluid transportation patterns [9], analysts observed excessive hauling distances (> 40 kilometres) taking place with regular frequency.

The underlying cause of excessive hauling distance may be due to contractual obligations or naïve operator dispatch; in either case, excessive hauling distance can be minimised with optimisation routing techniques. Utilising the Data-Driven Modeling (DDM) and Data-Driven Predictive Analytics (DDPA) approaches, a saltwater disposal fluid transportation pattern study was performed to estimate hauling distances from production to disposition.

Results from their case study at Andrews County, Texas, showed that disposal of produced fluids does not always materialise at adjacent facilities, which raises the expense of disposal. By using data-driven workflows, it is possible to strategically locate and optimise saltwater disposal facilities and the transportation infrastructure that supports them, opening the door to reducing disposal costs.

4 SALTWATER MANAGEMENT AND TREATMENT

4.1 Wastewater Injection

One of the biggest challenges associated with maintaining the favourable economics of unconventional O&G development operations is managing the produced water. How the produced water is handled is dependent on local resources, local regulations, and economics. Its fate is also highly influenced by three major factors: quantity, duration, and quality.

Infrastructure and geological conditions play a role in determining viable options as well. Oil reserves commonly have larger volumes of water than gas reservoirs. For example, the Marcellus Shale formation (a gas play) typically generates the lowest quantity of produced water when compared to the six other key basins in the United States. In contrast, the Permian Basin (a series of predominantly oil plays) has the highest amount of produced water [10].

Saltwater disposal wells, one form of Class II wells, are the most popular option for produced water management in the conventional and unconventional oil and gas industry because they are frequently the most cost-effective choice.

Figure 5. Typical Class II injection well. Source: https://www.dmr.nd.gov/oilgas/undergroundfaq.asp

Through the use of SWD wells, fluids are injected into underground formations, often over a mile below the surface, into subsurface zones that already contain naturally occurring saltwater. SWD intervals must be sealed above and below by an unbroken, impermeable rock layer.

Figure 5 displays the three casing layers typically required to protect overlying groundwater. The first protective layer comprises steel pipe from the ground surface to the base of the deepest usable quality groundwater. This surface casing also acts as a protective sleeve through which deeper drilling occurs. The second protective layer is a pipe inside the surface casing that extends the total depth of the well. It is permanently cemented in place. The third protective layer is the injection tubing string and packer. The tubing/packer assembly is what the produced water flows through to reach the underground formation. It contains individual sensors that are monitored to detect any pressure changes that may indicate a leak or other type of mechanical issue.

4.2 Wastewater Treatment

If SWD is the terminal point for produced water, then further processing is not required, but it is frequently completed to prolong the life of the disposal well. Upon produced water entering an SWD facility, oil generally constitutes 0.1%–0.5%. The progression of produced water through the SWD facility traditionally begins by allowing remaining organics and water to separate via gravity flow by hydrostatic pressure. After separation, the remaining hydrocarbons range from about 20 to 40 ppm (0.002%–0.004%).

In the Permian Basin and other regions where iron is a concern, iron reducers are added to prevent scaling. Solids are then collected from the base of the separation holding tanks and 200μm filters the produced water passes through. Surfactant is added to emulsify any remaining organics, followed by well injection. The greatest challenge with SWD is keeping up with the demand in high-production regions. A bottleneck can be formed at a disposal site based on how quickly water can be injected into the ground without over-pressurising the well. The rate at which the produced water can be injected into the ground can vary significantly across a given formation.

4.3 Narrative Description of The Process

We use a case example [11] to depict the step-by-step process narrative:

Incoming oil and gas waste will be offloaded into above-ground storage or settling tanks. Oil-based mud (OBM) and fluid waste will be unloaded via a closed-conduit system connected directly to a scalping shaker screen to begin processing. The fluid wastes will be pumped through a shaker screen to separate any solids. The separated saltwater will then be pumped to the on-site Class II Injection Well for disposal. The separated solids will be transferred to one of two 800-cubic yard Solids Storage Containers.

Water-based mud (WBM) will be unloaded via a closed-conduit system connected to storage tanks. The Washout/Collecting Pit will receive wash water from the waste hauling vehicles and frac tanks.

Oil- and water-based muds will be processed through a shaker screen. The liquid portion of the mud slurry will fall into a Mud Tank. The resulting solids will then be processed through a centrifuge. Once the solids are sufficiently dry, they will be directed to the Movable Solids Collector and transferred to a hopper and then to a rotary dryer. The dryer unit is designed to dry and heat the soil at temperatures between 300°F and 900°F to vaporise the hydrocarbons in the soil.

After the solid waste is discharged from the dryer, it is conditioned by cooling and adding moisture to the soil conditioner unit. The soil conditioner unit discharges the conditioned solids into the Solids Storage Containers for testing. The partially treated waste will be sampled for the parameters listed under Permit Condition VI.B.1. (Reusable Product) and then stored in the Solids Storage Container and/or the Moveable Solids Container until analytical test results have determined that the final reuse and disposition location for each load meets the criteria. Solid waste generated during the separation process or mixed product that does not meet the limitations specified in the permit must be returned to the mixing cycle, reprocessed, and reanalysed until it meets the required parameter limitations or must be disposed of at an off-site permitted disposal facility. The reconditioned mud is pumped into storage tanks before being sold for off-site reuse.

Excess oil from the OBM Storage Tanks will be pumped into a mobile heat treatment unit for oil recovery prior to being sold.

Figure 6. Alberta province in Canada holds companies accountable for their oilfield waste. Source: https://www.aer.ca/providing-information/by-topic/waste-management

5 CONCLUSIONS

The expansion of oilfields (mainly unconventional) will inevitably be required to meet the growing energy demands in the world. Currently, the most cost-effective choice for oil and gas-associated wastewater is disposal in Class II disposal wells. However, in order to maintain responsible practices, the development of cost-effective recycling technologies that allow produced water to be reused in an economical fashion is essential.

There are several oil and gas plays with large enough volumes of produced water that make them suitable markets for investigating recycling options. A single technology is not a practical option for treating produced water due to its complex and highly variable biogeochemical composition. Instead, viable treatment options need to be a series of techniques that are inexpensive, modular in design, have a low tendency for fouling, can handle significant throughput, and are able to desalinate effluent if recycling for other industrial applications is the ultimate objective.

Concerns about water usage and contamination can be addressed through continued research into practical and cost-effective reuse and recycling options.

6 REFERENCES

[1] https://www.epa.gov/uic/general-information-about-injection-wells

[2] https://www.epa.gov/system/files/documents/2022-06/fy23-24-oeca-draft-npg.pdf

[3] McIntosh, J. C., & Ferguson, G. (2019). Conventional oil—The forgotten part of the water‐energy nexus. Groundwater, 57(5), 669-677.

[4] EPA. 2017. National Underground Injection Control InventoryFederal Fiscal Year 2016 State and Tribal Summary

[5] https://www.science.org/doi/full/10.1126/sciadv.1500195

[6] Cheremisinoff, N.P. and Davletshin, A. (2015). Water Utilisation, Management, and Treatment. In Hydraulic Fracturing Operations (eds N.P. Cheremisinoff and A. Davletshin). https://doi.org/10.1002/9781119099987.ch5

[7] “Land-Based Disposal of Flowback Water Resulting from Hydraulic Fracturing of Gas Wells in the Marcellus Shale,” Cody C. Cogan, Pennsylvania State University, May 2013.

[8] https://www.jwnenergy.com/article/2020/10/26/repurposing-another-tool-to-address-albertas-backl/

[9] Ettehadtavakkol, A. (2016). Regional Saltwater Disposal Facility Planning Utilizing Data Analytic Methods.

[10] Liden, T., Clark, B. G., Hildenbrand, Z. L., & Schug, K. A. (2017). Unconventional oil and gas production: waste management and the water cycle. In Advances in Chemical Pollution, Environmental Management and Protection (Vol. 1, pp. 17-45). Elsevier.

[11] https://rrc.texas.gov/media/nkabs45q/waste_management_milam_stf-0121.pdf