CASE STUDY
Electro-Catalytic Oxidation of Oil and Natural Gas Process Streams
Introduction
Oil companies continually review new technologies for treatment of oily wastewater in order to stay ahead of the ever
increasing environmental regulation.
Aquatic Technologies has developed a proprietary electrolytic oxidation process uniquely suited for the treatment of
Produced Water, Barge and Bilge Water, and Drilling Mud for the reduction of Petroleum hydrocarbons.
The use of electrolytic oxidation for this purpose is new, and uniquely situated as an economical solution for both on-
shore and off-shore treatment processes for Drilling operations. Aquatic Technologies has completed several on-site
demonstrations of the process, and one final installation using their electrolytic oxidation technology to perform
emulsified oil supercoagulation and hydrocarbon/Aromatic reductions to exceed the upcoming 2009 EU Discharge
Standards. The advantages over conventional systems has been well demonstrated, and surpasses several currently
under development by other companies, including cross-flow and vibratory membrane technologies.
This electrolytic oxidation system, referred to as the EOH2O process, is manufactured by Aquatic Technologies at it's
fabrication plant in Newberg, Oregon.
What is Produced Water?
Oil drilling operations, both on-shore and platforms at sea, create large quantities of petroleum contaminated water,
referred to as “Produced Water”. This water is both naturally present in most underground oil reservoirs (known as
Formation Water) and also the result of water or steam injection to help force oil to the surface as the reservoir levels
decrease (referred to as Injected Water). Both are referred to as Produced Water and contain high levels of oils and
other petroleum by-products (such as benzene and toluene).
Average Produced Water amounts can equal 8x more water then the oil produced and/or removed from the reservoirs.
Such volumes represent immense volumes of petroleum contaminated water that requires economically viable and
environmentally responsible treatment methods to allow discharge of the water back to the sea.
Produced Water Regulations
International conventions have set provisional targets of 40 mg/l for hydrocarbons in offshore operational water
discharge. Any level of water discharged with over 100 mg/l of hydrocarbons is considered an oil spill. Additional targets
and/or treaty regulations in specific locations, such as the North Sea, have adjusted these targets to 30 mg/l by 2006,
and 5mg/l for 2009. Any discharge of Produced water containing these levels or less of hydrocarbons is allowed without
levy or charge against Carbon Credits. Exceeding the regulatory level increases the available Carbon Credits, which
can be applied against any levy should higher levels be discharged due to accident.
Aquatic Technologies electrolytic oxidation process has demonstrated the ability to reduce residual hydrocarbon levels
in Produced Water below that of the 2009 EU target.
Produced Water Re-Use and Discharge
Four approaches are utilized to resolve the Produced Water problem:
1) Avoid water production from the well
2) Inject the water back into a separate discharge well
3) Inject the water back into the same well
4) Treat the water for disposal
During early stages of oil production from wells, injected water is not needed. The Produced water is that which is
naturally present (Formation Water). Where applicable, other wells are drilled at the site to allow for Produced water to
be re-injected and thus disposed of. This method can be expensive, and also requires the injection well be sited a
significant distance from the oil production well.
In later stages of the well, water injection is required underneath the oil layer, normally through a porous soil formation.
The injected water produces pressure, raising the water to the top of the well, allowing it's removal. Because the water
will have to pass through varying soil and rock layers, it must be treated so that plugging of the formation does not
occur. Scaling and oil levels in the injected water must be controlled to achieve maximum results. Scale forming anions
like carbonates and sulfates must be within a required minimum/maximum range to prevent precipitation with metals in
the soil and rock that would reduce effectiveness of the injection water.
Disposal wells are particularly problematic and expensive at sea. Additionally, the level of Produced water is normally
much greater then the level of injected water, leaving a large volume of water that needs to e disposed of. No matter
how good conventional treatments are – the produced water will retain traces of oil, and thus direct discharge is strictly
controlled. In arid areas this treated water can be viewed as a natural resource, and most rightly should, as the amount
of freshwater is limited and thus properly treated Produced water should be of utmost importance.
Onshore and Offshore Treatment
Effective offshore treatment has historically been limited by both available platform space and sufficient time to treat the
volume being produced 24-hours a day, 7 days per week. Onshore treatment, where oily water treatment can be
intermittent due to availability of large storage areas, has allowed for batch and recirculating treatment regimes.
Offshore treatment must rely on rapid treatment regimes. Reliance on electrostatic precipititators, plate or DAF
separators, centrifuges and hydrocyclones, skim piles, and membrane filters remove the majority of organic solids and
heavy oils.
Size and number of equipment is also hampered by weight restrictions, which are normally set at 250lbs per square foot.
Because of these size and time constraints, offshore Produced water can contain as much as 10x that of onshore
facilities. One option that has been employed to address both the reduced time and space on offshore platforms is the
use of Storage and Offloading vessels (referred to as FSO's and FPSO's) as treatment shipments. Such floating
facilities however have been hampered by the ship's movement from swells, and the resultant effect on the treatment
process, leading to discharges considerably above regulation.
Additional Discharge Problems
Produced Water, from the vary nature of the oil and the need to drill through various rock and soil types, contain high
levels of heavy metals and other organic pollutants. These metals can include iron, copper, barium, beryllium, cadmium,
nickel, lead, silver, chromium, zinc, and even some radionuclide's such as radium-226 and 228.
When diluted and mixed with other seawater in deep offshore locations, treated Produced water is a minimal or
negligible environmental hazard. The hazard being more related to suspended solids or Turbidity as the solids settle out
of the water column. In shallow waters near shore or for onshore discharges to inland waterways or bodies, the elevated
levels of heavy metals and residual hydrocarbons are toxic.
Chemical treatment of oily water that is now becoming of greater environmental concern, is the use of flocculating
polymers to reduce the oil content. The residual life of these polymers int the environment is becoming of greater
concern to the biological and medical community. Additionally, the use of such chemical additives requires the proper
storage and handling of the chemicals, as well as additional treatment regimes, increasing liability and operating costs,
as well as adding millions of tons of additional chemical wastes to the ecosystem.
Along with the hydrocarbons, heavy metals, and radionuclide's that Produced water will contain, various other dissolved
solids must be removed to one degree or another to allow discharge or even re-use in the drilling operation.
High levels of dissolved solids are difficult for conventional gravity separation devices to handle (DAF, cyclones,
centrifuges, and clarifier's). This requires different technologies, and one's best employed after the initial oil-water and
heavy solids separation has occurred.
Other Dissolved Solids in Produced Water
The 1995 American Petroleum Institute report denoted the following contributing factors to toxicity from Produced Water:
1. Small particulate
2. Salinity (9% or greater by volume)
3. Extractable organics (acidic, basic, neutral)
4. Ammonia
5. Hydrogen sulfide
6. Volatile compounds (BTEX)
There are no single, stand alone technologies that exist today for either Onshore or Offshore treatment of Produced
Water that can resolve all the pollution issues. The existing technologies must be used in an integrated fashion, as
some are much better economically for separating large volumes of oil from water, rock and large drill cuttings from oil
and water, removal of volatile organics and hydrogen sulfide, or organic compounds, but are susceptible to severe
fouling if attempting to perform all these duties singly.
Many have high operation costs or totally unfeasible for placement on an offshore platform either due to size and
weight. Others are small, but create large volumes of secondary waste streams that must be shipped to shore for further
processing, and thus substantially raise operating costs.
Conventional technologies include Carbon and/or Bentonite Absorption; Air Stripping; Ultra-violet Light; Biological
Treatment; Chemical Oxidation (peroxide and/or ozone); or Membrane and Nano-Filtration.
All have advantages and limitations, and these differ from on to the other depending on where the treatment process is
situated (Onshore v. Offshore).
For all intents and purposes, biological systems are unsuitable for Offshore applications. Additionally, chemical oxidation
treatments using hazardous chemicals such as hydrogen peroxide and/or Ultra-violet light with Ozone gas injection are
also unsuitable and normally can not meet the CAPEX/APEX safety requirements for Offshore Platforms or On-board
Ship. Bentonite and carbon absorption will work and is currently utilized on various platforms around the World.
Unfortunately, both require heavy maintenance and create large volumes of secondary waste, averaging as much as
$400,000 per day in transport costs per platform for taking the wastes to shore for further treatment and disposal.
Air stripping is normally not utilized separately, as the equipment is easily fouled by oil and normally requires some gas
scrubbing due to the off-gassing of volatile wastes.
However, until now, they have been the conventionally accepted treatment regimes and are widely utilized throughout
the industry.
The EOH2O Electrolytic Oxidation Treatment
In 2002, an engineering firm in Aberdeen, Scotland approached Aquatic Technologies concerning it's patented
electrolytic oxidation processes ability to remove Total Hydrocarbons (THC), Aromatics, and Aliphatics from Produced
and Barge-Bilge Washout water. The issue was whether the small footprint of the electrolytic oxidation technology could
remove the residual petroleum products in the wastewater either before, or following pretreatment by the firms
proprietary oil-water coalescing equipment.
The problem had been raised by several of the major Oil production companies in the North Sea, as well as the onshore
treatment firms handling barged-in Produced and Mud Water.
A in-field test unit was built and shipped to Scotland for trials. The unit did not utilize any on-board filtration, as the
purpose was to determine what the effect on bot high level oil water, as well as that containing low levels of emulsified oil
residues following treatment by conventional means.
The unit was placed at a local Hazardous Wastewater Transfer companies site. Samples of Produced water, Drilling
Mud, and Barge Washout water were ported to the site for testing.
Initial Tests began on Oil Barge Washout Water. Results by independent lab analysis were as follows:
Incoming Wastewater: Post Treatment (Supernatant)
THC: 10,041 mg/l 4.87 mg/l
Aromatic Hydrocarbons : 1094 mg/l 0.83 mg/l
COD: 9680 mg/l 1680 mg/l
pH: 7.19 7.57
Suspended Solids: 2282 mg/l 48 mg/l
The results denote the levels at time of sampling of the supernatant. Supernatant is the water below the coagulated oil
floating at the surface of the water.
An unexpected, but desirable result means that thousands of barrels of oil can be recaptured directly from the
wastewater – increasing the amount received from the platform and reducing treatment costs.
The results were noted several times using differing Washout waters over a twelve month period.
Drilling Mud wastewater was also tested, with the main emphasis being on the cleaning of the solids of hydrocarbon
residue. The tests were performed as simple batch treatment, rotating the solids and wastewater as one unit. A greater
then 50% of the THC and Aromatic content of the Drilling Mud was reduced by the EOH2O process (the sampling did
not draw from the supernatant, but only from water “in motion”. Results reported as COD – untreated sample 8210 mg/l.
Following EOH2O treatment – 3900 mg/. The intent of the trial was not to reach “0” but determine feasibility).
The results of the initial trials convinced the Nicols Wastewater Transfer Station in Aberdeen, Scotland to purchase the
demonstration unit in June of 2005. The unit now operates on a 6,000gpd batch system to remove the residual
emulsified oils from Barge Washout water for re-sale to the local oil refinery, and discharge of the treated water to the
local municipal wastewater plant without incurring levy.
Additional Testing
Based on the results on Barge Washout water, British Petroleum agreed to barge in both Produced Water and Drill
Cutting Water for continued Onshore treatment feasibility testing. These trials continue in Aberdeen at the time of this
report. Additionally, Petrofac, in conjunction with British Petroleum, wanted to performed Onshore testing of the EOH2O
process for the treatment of condensate from pumping of natural gas from Offshore platforms.
BTEX and MEG in Natural Gas Condensate
Not all Offshore platforms are oil platforms in the North Sea or Gulf of Mexico. Many platforms, as many as 40%, are
involved in the capture and pumping to shore of Natural Gas.
Natural gas wells contain water and water vapor. During pumping, this water condenses inside the pipeline. Due to the
depth and cold of the surrounding water in the North Sea, the well requires additions of various glycol solutions to
prevent the water from freezing and plugging the pipeline. Thus the condensate or captured water at the shore will
contain not only low levels of oil, but also volatile
hydrocarbons such as Benzene, Toluene, Ethylbenzene, and Xylene; as well as glycol types such as methanol,
diethylene glycol, and triethylene glycol (referred to as MEG collectively).
Various treatment processes are not conducive to treatment of these pollutants, due the high levels of sea water, as well
as the fact that all treatment regimes must meet ATEX safety concerns. This removes many of the conventional
treatments such as ozone, and UV-hydrogen peroxide unusable. Additional considerations are cold-weather inhibiting
biological treatments, and the high cost of dealing with secondary waste streams where carbon or other absorbent type
materials are used.
In a joint effort with Petrofac, one of the largest On and Offshore Oil and Gas refinery operating companies, condensate
from the Bacton Natural Gas Plant in England was provided to determine feasibility of the EOH2O process for reduction
of BTEX and residual MEG (the plant operates a MEG recapturing process for re-use – reducing the level of MEG in the
condensate. This is a standard practice in the industry).
As previously with the Oil Barge Washout water, initial testing was to determine feasibility, as well as expected equipment
size and treatment time, and not necessarily to reach “0” of the pollutants, as it was expected that modifications to the
process would have to be made – such as the inclusion of mechanical filtration to remove oxidized organics and heavy
metals, to meet UK. And EU Discharge to Ocean Standards.
The following is the reported analysis of two different trials:
Condensate Test #1 (provided as mg/l):
Untreated Condensate Treated Condensate
pH 6.0 6.59
Suspended Solids 44 58
Total Hydrocarbons (THC) 27 6
Aromatic Hydrocarbons 17 0
Other Organic components NA NA
Total Organic Components NA NA
Benzene NA NA
Toluene NA NA
Ethylbenzene NA NA
Xylene NA NA
Methanol NA NA
2-Butoxyethanol NA NA
Condensate Test #2 (provided as mg/l):
Untreated Condensate Treated Condensate
pH 4.11 4.43
Suspended Solids 74 32
Total Hydrocarbons (THC) 53.09 6.06
Aromatic Hydrocarbons 50.34 5.11
Other Organic components 4364.92 2753.36
Total Organic Components 4418.01 2759.42
Benzene 37.57 2.22
Toluene 9.54 0.45
Ethylbenzene 0.23 0.0
Xylene 1.16 0.29
Methanol 194.9 161.7
2-Butoxyethanol 4168 2588
The tests determined that the glycol recover unit at the plant was malfunctioning, as expected methanol and 2-
Butoxyethanol concentrations were expected to be less then 100 mg/l in the initial untreated sample.
Based on these results, Petrofac and British Petroleum have asked for an ATEX rated full scale pilot trial to handle
100m3pd of condensate for the Bacton Plant. It is expected that this unit will be in place and conducting trials by the end
of the 3rd Quarter of 2006.
The test results for the volume treated in the time and space provided, exceeded reductions available from all
conventional treatment regimes except Reverse Osmosis. However, since the EOH2O process requires electrode
replacement approximately once ever 2-3 years, the estimated operating cost of the EOH2O process to handle
100m3pd of condensate, including suitable mechanical filtration of the oxidized solids, is 1/80th that of conventional
Reverse Osmosis systems.
Conclusion:
The EOH2O process has demonstrated the ability to treat Produced, Oil Barge Washout and Drill Cutting waters;
1. Without the use of hazardous and/or environmentally damaging chemicals
2. Without the creation of secondary waste streams requiring shipment to shore for further treatment.
3. Reduce BTEX, THC, and Aromatic hydrocarbons to levels below that currently available by membrane technology.
4. Can operate in an Onshore ATEX environment.
5. Has a significantly lower operating cost then membrane technology.
6. Demonstrates ability to convert to full scale sizing for condensate and
Barge Washout water treatment.
7. Applicability of Offshore or FPSO is possible, but requires additional design modifications and integration with other
oil-water separation technology in order to handle the large volumes of Produced water under limited space
requirements.
End 4/06