Exploration and producer(E&P) companies in the oil, natural gas and even coal industries are caught in a perfect storm. On the one hand, they are under pressure to increase production to meet growing U.S. and international demand. On the other hand, there is a growing shortage of fresh water. Exploration and production (E&P) activities require massive amounts of fresh water for operations; acquiring this fresh water is becoming more difficult and more costly.

Disposal of the contaminated water generated during E&P operations is an even bigger problem. 18 billion barrels of produced and flow back water are generated nationwide annually. While much of this water can be injected back into the ground, 30% or more must be disposed or treated by alternative methods.

E&P companies are coming under significant political and regulatory scrutiny for traditional disposal methods, with concerns rising over environmental damage and public health. The costs of disposal, both in dollars and in terms of public image, are skyrocketing. Most E&P company executives will tell you that the energy industry is on the brink of a national crisis.

In the following discussion, we refer frequently to the North Dakota Bakken and Williston Basin development area due to its rapid growth and known difficult waste water problems. However, the technology and methodology shown below is applicable to virtually any exploration and production field.

To obtain more information and begin a detailed person-to-person discussion of the possible match between your oil or natural gas waste water problem and the technology we are offering, please fill out the questionnaire at the end of this discussion - it will provide important on-site information which will assist us in quickly determining what arrangement of our processing modules are needed to meet your specific needs.

Thanks for visiting our site - this is an important and growing environmental issue - we hope the information presented here will assist you in your search for the proper water processing/treatment technology.



Regardless of what the current White House Administration says or tries to have the public conform to, (with windmills, solar panels in the desert or on top of their home, expensive electric cars constructed from discarded cereal boxes and so forth), oil and natural gas will continue to be America's most plentiful and reliable supply of energy for the foreseeable future.


In this series of pages we will introduce a relatively new yet simple waste water processing system which will provide three significant benefits to the oil and gas industry:

(1) An ability to process and reuse to a great extent the potentially bothersome and harmful waste water which is present in all phase of operation at all oil and gas wells;

(2) Provide a substantial reduction in the amount of fresh water, mainly drawn from dwindling aquifer resources, which is required to effectively activate the "fracking" process which is rapidly becoming one of the primary methods of oil and gas extraction.

(3) A significant reduction in the "carbon footprint" of oil and gas producers who, with this new technology, can substantially reduce or even eliminate the airborne pollutants produced by the transportation of waste water to either injection wells or central processing facilities.

As noted above, these are three issues which daily confront oil and gas producers and which attract government agencies and environmental activists like bears are attracted to honey. Helping alleviate these three problems will allow domestic oil and gas exploration and extraction to proceed in a more orderly, cost effective and less intrusive manner to the surrounding environment.

While the technology described below is NOT designed to somehow increase the amount of oil or natural gas which can be produced from a given site, some observations later in the discussion will illustrate the benefits of retaining a certain amount(and type) of material in the re-fracking use of waste water. Nor is this technology capable of reducing the price of gas at the pump. Its objectives are primarily environmentally oriented, with the three objectives noted above as its key features.



Natural gas is comparatively inexpensive and due to its plentiful nature in the US is forecasted to be a significant export in coming years. Unfortunately, this resource comes with some serious waste water baggage as we shall see later.

The above graph not only shows the expected production of natural gas in the US in coming years, but also illustrates that an increasing percentage of the recovered gas will be extracted from shale. Unless effective exploration, extraction methods and waste water management techniques are developed and implemented over the next generation, it is possible this extensive natural resource may not meet its potential in fulfilling major portions of our nation's energy needs.

With the projected, increased production will come increased fresh water needs linked directly with the problems associated with increasing waste water from both exploration and production.


Shale is also the "home" for much of the estimated recoverable oil in the US. However, beginning in the early 1980s, oil shale was not on the U.S. energy policy agenda, and very little attention had been directed at technology or energy market developments that might change the commercial prospects for oil shale.

However, new drilling and extraction processes have changed all of that....and very rapidly.

While both shale and conventional oil exploration and production both exhibit waste water issues as discussed below, the higher profile and more extensive and controversial oil and natural gas exploration and extraction processes occur in shale substrates. The technology described below will deal with waste water obtained from both types of extraction processes as well as conventional, non-fracking extraction procedures.

Huge oil reserves are being discovered nationwide that far exceed estimates just a few years ago. The greatest percentage and largest reserves are in shale. Therefore, in this initial discussion, we will use shale waste water as an example in the waste water discussion; but the technology as noted above is applicable to both types of extraction environments.

For example, in April 2008, the U.S. Geological Survey raised its estimates of recoverable oil reserves in the Bakken Formation of North Dakota and Montana. The figures, as high as 4.3 billion barrels of oil, represented about a 2,400% increase over earlier estimates.

Less than three years later, production in the Bakken is booming, unemployment is the lowest in the nation, investors are flocking to the area and the estimates of recoverable reserves are soaring anew as new technology opens up shale plays in the region and across the country.

The president and chief operating officer of Continental Resources (CLR), the top producer in the Bakken contended at that time that the Bakken holds as much as 24 billion barrels of oil that can be recovered with current technology. That was a year ago. Today(March 2012) the estimate is now close to 165 billion barrels.

If true, it would amount to one the world's largest individual oil reserves.


Another of the largest deposits of shale oil in the world is found in the United States in the Green River Formation, which covers portions of Colorado, Utah, and Wyoming. Estimates of the oil reserves in place within the Green River Formation range from 1.2 to 1.8 trillion barrels.

Not all reserves in place are recoverable. However, even a moderate estimate of 800 billion barrels of recoverable oil from oil shale in the Green River Formation is three times greater than the proven oil reserves of Saudi Arabia. Present U.S. demand for petroleum products is about 20 million barrels per day. If oil shale could be used to meet a quarter of that demand, the estimated 800 billion barrels of recoverable oil from the Green River Formation alone would last for more than 400 years.

Same for the Bakken and the Williston Basin shown above.


More than 70% of the total oil shale acreage in the Green River Formation, including the richest and thickest oil shale deposits, is under federally owned and managed lands. Thus, the federal government directly controls access to the most commercially attractive portions of the oil shale resource base. If you like to file Environmental Impact Reports, this is the place where you can be occupied for the next century.

President Obama and his Secretary of the Interior have desperately tried to place more and more open range and high desert areas(where the Green River Formation is found) under federal control so as to limit or stop exploration and extraction of both oil and gas. This is similar to President Clinton's "scorched earth" program in Utah prior his leaving office. The present Obama effort is similar and is a part of the Administration's continuing and intensive multi-phase effort to replace oil and natural gas with solar panels, windmills and of course more electric cars constructed from cereal boxes and exploding lithium ion batteries.

Once the land is under federal control, no permitting would be allowed, no trees cut and not even a single boulder could be removed from millions of acres without an Environmental Impact Study - similar to the politically fired Keystone X pipeline project which traverses small portions of public lands in Western Nebraska.

For details of this extraordinary "land grab" effort by Obama, see


In the following discussion we will focus primarily on the use of private lands and dealing with the waste water produced in that environment. Even so, exploration, production and waste water disposal in these areas is a serious problem.


FRACKING AND FLOWBACK WATER. As with natural gas, the oil reserves noted above are imbedded in shale and the latest technology being used(and rapidly becoming a household word) is "fracking" or "hydro-fracking" - the injection of massive amounts of water and selected chemicals, sand and minerals so as to fracture or open up fissures in the deep shale layers. Once these fissures are opened, the fluid injection process stops and huge amounts of the fracking water, called "flow back water" comes back up the wellhead.


Large volumes of oil(or natural gas) are then released from the fractured shale and can be extracted. A million or more gallons of fracking water are typically injected over several days or weeks which produces a significant amount of waste "flow back water" when the high pressure fluid injection process ceases.

Raw water from which the frack water is produced is many times extracted from fresh water aquifers or surface sources, depleting a dwindling supply of water that is also used for irrigation and agricultural activities.

The technology described below will significantly reduce the amount of fresh water needed to conduct the extensive fracking operation in shale-based oil or natural gas exploration and extraction.

PRODUCED WATER. On the other hand, "produced water" is naturally occurring water found in the sedimentary shale beds traversed by the well bore. It is generally very saline in nature and comes up together with either the oil or national gas and presents another environmental challenge for shale drillers.

Because the water has been in contact with the hydrocarbon-bearing formation for centuries, it contains some of the chemical characteristics of the formation and the hydrocarbon itself. It may include water from the underground reservoir, water injected into the formation, and any chemicals added during the production and treatment processes.

It can have a very high salinity and total dissolved solids (TDS) as shown in the following graphic. Produced water, sometimes referred to as "brine" or "formation water" picks up various minerals from the shale formation including barium, calcium, iron, chloride, sodium, magnesium and sulphur.


There is a point where the water that flows up a well shifts from being primarily recovered fracturing fluid to that of produced water. The dividing line can be difficult to discern, yet can be distinguished by comparing the different chemical signatures of the recovered frac fluid to that of the naturally-occurring shale formation water.

To summarize, the major constituents of concern in produced water are:

o Suspended solids

o Microbiological contaminants

oSalt content (salinity, total dissolved solids, electrical conductivity)
o Oil and grease (this is a measure of the organic chemical compounds)
o Various natural inorganic and organic compounds or chemical additives used in drilling and operating the well
o Naturally occurring radioactive material (NORM)

Produced water is not a single commodity and may vary considerably depending on the geographic location of the field as shown below, the geological host formation, and the type of hydrocarbon product being produced. Produced water properties and volume may even vary throughout the lifetime of a well's operation.


Produced water is by far the largest volume byproduct or waste stream associated with oil and gas exploration and production.

It is estimated that approximately 21 billion bbl (barrels; 1 bbl = 42 U.S. gallons) of produced water are generated each year in the United States from nearly a million wells. This represents about 57 million bbl/day, 2.4 billion gallons/day, or 913,000 m3/day (Clark and Veil 2009). More than 50 billion bbl of produced water are generated each year at thousands of wells in other countries. This is a lot of waste water to either spread on the ground, place in injection wells or somehow process to recover useable water for additional fracking or other uses.

Early in the life of an oil well, the oil production is high and produced water production is low. Over time the oil production decreases and the water production increases. Another way of looking at this is to examine the ratio of water-to-oil.


Clark, C.E., and J.A. Veil, 2009, Produced Water Volumes and Management Practices in the United States [external site], ANL/EVS/R-09/1, prepared by the Environmental Science Division, Argonne National Laboratory for the U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory


Worldwide estimate - 2:1 to 3:1
U.S. estimate - 2:1to 8:1. Many U.S. fields are mature and past their peak production and will fall in the higher end of this range(ibid. Clark and Veil 2009), although the ratio may be even higher. Many older ("legacy" or "stripper") U.S. wells have ratios > 50:1. "Young" wells will have ratios in the lower end of this range.

At some point, the cost of managing the produced water exceeds the profit from selling the oil. When this point is reached, the well is shut down by either capping or plugging. Some areas, such as North Dakota, do not permit capping and if a new well is needed nearby, the drilling process must start from scratch.


So here we are - sitting on my North Dakota farm and ranch in the rolling land of Western North Dakota - and looking over the immense Bakken oil reserve. Let's see what the new waste water technology can accomplish in this difficult waste water environment(as can be seen from the bright red areas in the upper midwest above).




In the following analysis, it is important to determine how much flow back and/or produced water could be expected in a given field or individual well. After that, it will be important to determine what type of processes will be required for flow back water versus produced water as not only the volume but the composition will likely be different, both from the same well or from different geographic areas.

Using the Bakken as an example; as of January 2012, there were 6600 active wells in North Dakota. By comparison, California had active 49,000 wells but was producing LESS overall than the 6600 North Dakota wells. Typically, the lifetime of these wells can be 35 years or so, with some extension of that lifetime by "re fracking".


How these wells are located with respect to each other, in addition to where they are geographically located, and what type of water composition there is in the produced and flow back water, and how much produced or flow back water is required to be processed(or currently trucked away) will determine how the proposed technology will be modularly structured to accommodate these variables.

In general, one size or design will not fit all, either in volume or by type of contaminant(s) that need to be processed and eliminated or collected.


Oil production from a given well in the Bakken can range from perhaps 1000 to 3000 barrels(42 gallons per barrel) per day to some super performers at up to 6000-7000 barrels per day. For four wells located on adjacent 640 acre tracts, one might ideally see 20,000 barrels per day of oil(800,000 gallons) daily. More conservatively, assuming an average of 4000 barrels per day for an actively producing well and using a conservative 2:1 ratio(from the above discussion) for produced water to oil for relatively new wells, it is likely that up to 320,000 gallons of produced waste water may be encountered daily from EACH producing well in this 4 square mile tract.

The oil extraction process in the Bakken is higher on the average then other fields - so it represents potentially the largest volume of waste water that needs to be processed or hauled away in the lower 48 states. Much is stored on site as shown below or carted away in a never ending line of tankers to dispose of the waste. To haul 320,000 gallons of waste water even 50 miles to a central processing facility(which may not exist in North Dakota as shown below) for each active well costs a lot of time, labor and truck fuel and produces a lot of airborne contaminants. If all of the waste has to be trucked away, 50-55 tanker have to make the trek every day, for each well, clogging highways and back roads.


All of this costs money and with the average cost of extracting oil in the Bakken around $12-$14 per barrel and which currently returns the cost of capital at $40 per barrel, it is important that disposal costs don't excessively eat into any profit margin.


As shown above, not many off-site waste water disposal capabilities exist in several key oil and gas producing states. In particular, with the extraordinary growth of the North Dakota Bakken field, either additional offsite facilities will be required, or new, mobile waste water processing systems such as those described below will be required. Otherwise, the waste water needs to be stored and trucked to an injection well or placed in tanks or setting areas around the field.

The waste material from fracking and produced water is pretty ugly stuff as shown below - but with proper processing the water can be returned to a useable condition and the residue, which may contain valuable mineral or metal content, can be further reduced and distributed to agricultural or industrial entities who need such materials in their products.

It is important to remember that the waste water processing need not return the contaminated flow back or produced water to a completely pure condition.

In fact, many producers have found that a moderate amount of salts(chlorides, etc.) left in the processed water may actually increase the amount of oil or gas extracted as a result of using this less-than-pure water for re-fracking.

Injection wells are used in many parts of the country to dispose of both flow back and produced water. The Environmental Protection Agency(EPA) has begun to limit the permitting of such wells due to suspected contamination of aquifers used for municipal or rural drinking water. Although such situations are rare, activist environmental groups are not letting the possibility go to waste and continue to oppose the additional permitting of such waste disposal mechanisms.

There is also talk that the process of fracking and the use of injection wells are responsible for small earthquakes in various areas. Again, environmental groups use this currently unsubstantiated information and in some case are effectively blocking both exploration and production activities.



Before we continue, it is important once again to point out that the characteristics/composition of the flow back and produced water may differ to the extent where different types of waste water processing mechanisms need to be employed.

This may be required to return the water to a useable format or further reduce the contaminants to a manageable, low-water content residue and then further process this residue to extract valuable minerals, metals and salts for use either on or off-site.

Once the useable or harmful materials are extracted, the remaining dirt, clay or other inert residue may be disposed of in surface containment mechanisms.



The flow diagram below illustrates the basic elements of an oil or natural gas field operation where either flow back or produced water(or both) are present at the wellhead. The diagram for the most part speaks for itself - except to illustrate that in this case, the on-site may consist of a variety of cascaded water processing modules arranged so as to deal with the specific composition(and desired product(s)) which be encountered and produced, respectively. Additionally, the business model may vary depending on whether a local or remote processing capability is desired or even possible.



We recall from a preceding diagram that in the Bakken field and Williston Basin there are few if any centralized waste water processing operations.

With the planned increase in production in that field it will be important for any potential waste water processing operation to properly address both local(mobile) and centralized processing capabilities based on the various technical, cost and logistical parameters discussed on this web page.


Back to the diagram above.

In general, if the characteristics of the flow back and produced water are such that local processing is possible, and if the result of that local processing is suitable for water reuse in on-going fracking activity at the local or adjacent well(s), the business model will emphasize a preponderance of local processing and localized logistical activities.

If on the other hand, if it makes financial and logistical sense to transport raw waste water to a nearby centralized processing facility, then several of the model's on-site components illustrated below may become part of the centralized facility - but on a large scale.

An ideal situation would be to determine if, after local processing of the flow back or produced water, that the waste water can be reused for additional on-site or nearby water needs, then that model would likely exhibit the highest cost-effectiveness as one would expect.

However, with site specific water processing volumes and varying contamination issues which may be encountered from geographic area to area(even with the Bakken, for example), the appropriate configuration(modules) of the water processing system need to be derived from chemical analysis of one or both types of waste water on site(or nearby), current spot oil market conditions, transportation costs as well as the marketability and value of byproducts which could be extracted from the reside of the water processing operation.

Only then, knowing the capability of the individual modules, can one accurately specify what type of system should deployed to a given area; what type and value there is for any byproducts(metals, barium, etc.) which can be extracted from the waste water.

For the designer, the decision must be be made as to whether to build and deploy a system which "does it all" and is applicable to a wide range of oil and gas field conditions or alternatively takes a more conservative view and deals with site-specific conditions and provides a service, while not comprehensive in all aspects of waste water management and processing. The design then will fill a specific, significant and cost-effective portion of the environmental problem created by the rapidly increasing amount of waste water which will be found in rapidly growing fields like the Bakken, Marcellus or Green River areas.


Based on the variety of contaminants, types of water, volumes and need for either centralized or mobile processing that are required in a specific situation, the proposed system is organized in modules.

Each module can be operated independently or connected in a serial fashion to other modules, each having a specific function.

Knowledge of the constituents of specific produced waters is needed for regulatory compliance and for selecting management/disposal options such as secondary recovery and disposal. Oil and grease are the constituents of produced water that receive the most attention in both onshore and offshore operations, while salt content (expressed as salinity, conductivity, or TDS) is a primary constituent of concern in onshore operations. In addition, produced water contains many organic and inorganic compounds. These
vary greatly from location to location and even over time in the same well.

Since each oil or natural gas field may contain different contaminants, have different volumes of waste water to process and contain valuable minerals or metals in the waste stream, the field operation would require selecting the proper module(s) and arranging them in the proper sequence. This could be done in advance or configured in the field.

A typical field operation would combine advanced aeration and biological treatment technology with chemical precipitation and high rate clarification technology.

The simplest but perhaps most important module is shown below. It is called a Magnetic Ballast Clarifier(MBC). It is a patented water clarification process designed by MagSep to effectively remove all types of pollutant PARTICLES from wastewater.

While the use of magnetic technologies have been know for some time, the MBC system, with its companion modules, is what the engineering world would collectively call Best Available Technology(BAT) for a wide variety of reasons summarized in the table below,


A modestly sized(mobile as shown above) MBC(6000-10,000 barrels per 24 hours) is shown in the video below - in this case processing some pretty bad coal water.

As discussed above, the process of removing suspended materials from large amounts of water must be done quickly and with systems that are not the size of Yankee Stadium.

Click the start arrow on the short video clip of this mobile system in operation - processing highly contaminated water at approximately 150 gallons per minute.

The sample below is typical of what one would see in either flow back or produced water from a shale-based natural gas field. The processing shown below is just that related to suspended particulates. Other contaminants may remain, such as bacteria, organics, dissolved metals and inorganics and can now be separated by subsequent modules.



The MBC removes particles(suspended solids) by attaching them to a very heavy inert material and allowing them to settle rapidly and/or removing the particles magnetically.

Magnetite is the heavy material used because it is inert, non-reactive, and has a density over five times that of water so it settles very rapidly. Magnetite is also magnetic which allows it to be removed magnetically if needed. Lastly, magnetite is twice as dense as sand thereby allowing it to settle particles faster than sand ballast systems.

In the MBC system shown below, a small amount(perhaps 0.5 to 1.0 weight by percent) of magnetite is added to the water where the magnetite is then attached to pollutant particles with a proprietary flocculating polymer.

The magnetite/pollutant particle then settles rapidly and is removed by gravity clarification with finer particles removed magnetically if needed. Permanent rare earth magnets can be used to quickly remove these combined magnetic particles from the water.

The magnetic/pollutant is then mechanically cleaned by separating the magnetite from the pollutant particle with a shear mixer and the clean magnetite is then reused. The process is not subject to fouling from organics and the magnetite can be used over and over again.

In the table below, the MBC's features are summarized, together with the features of the other modules which are discussed now.


A fully integrated waste water processing system will include the MBC as discussed above as well as additional modules to deal with organic materials, bacteria and selected inorganic and heavy metal materials.


Bacteria can clog equipment and pipelines. They can also form difficult-to-break
emulsions and hydrogen sulfide, which can be corrosive. Should laboratory test indicate that various species of bacteria exist, the AIR-JAMMER module, described below, can be inserted into the waste water reduction process.

A conventional Mazzei or other venturi air inductor is used to create the micro bubbles, containing oxygen, into the water where the oxygen is then used to capture the typical, extra electron which microbes possess - thus disabling or destroying the micro-organism.


Hydrocarbons that occur naturally in produced water include organic acids, poly cyclic aromatic hydrocarbons (PAHs), phenols, and volatiles. These hydrocarbons are likely contributors to produced water toxicity, and their toxicities are additive, so that although individually the toxicities may be insignificant, when combined, aquatic toxicity can occur.

Produced water from natural gas operations includes condensed water and typically have higher contents of low molecular-weight aromatic hydrocarbons such as benzene, toluene, ethyl benzene, and xylene (BTEX) than those from oil operations; hence they are relatively more toxic than produced waters from oil production.

Being able to manage these organic chemicals is made possible by the E-BAC module summarized below. E-BAC is a stable liquid concentrate of 38 different species of naturally occurring micro-organisms, specially blended to treated petroleum oil and gas wastes. E-BAC, as shown below, is a powerful tool for degrading complex carbohydrates, proteins, fats, oils and grease - some or all of which are present in produced water, and many times in flow back water.

The use of microbial materials to degrade and break down complex organic compounds is becoming popular in municipal and industrial waste management circles.


The concentration of inorganic materials and metals in produced water depends on the field, particularly with respect to the age and geology of the formation from which the oil and gas are produced. Metals typically found in produced waters include zinc, lead, manganese, iron, and barium. Metals concentrations in produced water are often higher than those found in seawater.

Besides toxicity, metals can cause production problems. For example, iron in produced water can react with oxygen in the air to produce solids, which can interfere with processing equipment, such as hydro cyclones, and can plug formations during injection or cause staining or deposits at onshore discharge sites.

Extraction of some inorganic solids and most heavy metals is a two step process in the proposed system: (1) decrease solubility through the use of specific chemicals; and then (2) clarification or filtration to remove the precipitates of step (2). Sequential precipitation can be performed to separate toxic heavy metals from other sludge.



- Micro bubble production via injection venturi

- Oxygen attacks bio substances

- Reliable

- No moving parts

- Most cost effective bio system

- Self-cleaning/non-clogging

- Mobile

- High dissolved Oxy levels

- Low Energy Use



- Breakdown of organic/petrochemical wastes

- Degradation of complex carbs, proteins, fats, oils and grease

- Anaerobic or aerobic growth

- Lower BOD, TSS, FOG and NH3

- Odor and VOC emission control

- Low oxygen requirements

- Sludge Reduction

- Wastewater disinfection

- Robust organisms withstand toxicity of waste water


- Conversion of metals & salts to non-soluble/suspended condition

- Simple & easy to use

- Low energy use

- Lowers TDS

- Low capital cost

- Separation of heavy metals

- Produces marketable solid waste





- Removal of suspended solids

- Polymeric reaction produces magnetic floc

- Removal of flock

- Gravity or permanent magnets

- Recycling of magnetite for reuse

- Small size and low cost

- Low energy use

- Gravity operation

- Rapid startup/shutdown

- No fouling

- High water purity with low TSS

- Easy to operate

- Mobile; rapid re-location


Certain heavy metals, including the barium compounds used in the fracking process, have commercial value and are a product of the sequential solid separation process illustrated below.

About 80% of the world's barium sulfate production, mostly purified mineral, is consumed as a component of oil well drilling fluid. It increases the density of the fluid.

Barium coming up with flow back water is many times simply released to water and soil in the discharge and disposal of drilling wastes. In some cases, the flow back water is trucked away and sequestered in a special injection well.

We also know that a wide variety of salts and metals and organic compounds originate in most shale deposits and those salts and metals may have appreciable value to industry or agriculture.

The cascaded or serial process illustrated below can process all four categories of contaminants discussed above at approximately 1.5 million US gallons per 24 hours, far more efficiently, less costly and more precisely than any other oil or natural gas waste water processing system known today.




How the proposed system is used in the field or in a centralized processing facility obviously depends on the volume and type of contaminated water being handled on a daily or scheduled basis. In addition to the mobile unit illustrated above, more complex or larger volume system can be transported and operated in the field or at a centralized facility.


Existing/available frac tanks as shown above can be modified to accommodate several stages of the proposed waste water system. This particular configuration would be suited for operation in difficult environmental conditions yet remain portable should its capability be required elsewhere.

It is called a "full feature" processing system with all of the modules and capabilities summarized in the table above. It is also a "hard wired" configuration where internal and internal connections are permanent and its utility is one of maximum reduction of difficult waste water conditions.

The internal interconnections can also be "soft wired" so as to bypass modules that may not be needed in a particular situation, thus increasing possible thru put of the system.


Ocean-style containers modified for side-access are shown below. In this case, the water processor components are accessible from the side and can interchanged or replaced as needed to create a special capability to deal with specific waste water conditions and desired results or products. These types of containers are very popular when accessibility to controls, monitoring equipment or maintenance activities are expected.

For the containerized configuration, the individual processor modules are skid mounted and can be easily placed or removed from the proper interior location with a conventional front loader. Inter-module electrical and plumbing connections can be then made to the pre-wired and pre-plumbed water processing modules.

If such units are deployed in inclement weather/wind conditions, the access doors are located on the leeward side of the container's orientation, as determined in part by Wind Rose data from that particular site. This affords maximum physical protection for any maintenance crew needing access to the interior components.



An individual module of one of the water processors is shown below, illustrating how it can easily be trailer or flat-bed mounted for rapid mobility in or around the oil or natural gas field. The particular module shown below, depending on local waste water conditions is capable of process between 7000 and 10,000 barrels of waste water per 24 hour period.