REMOVAL OF PETROLEUM USING DUAL PHASE EXTRACTION

A. Scott McDowell, MS, REM

Hayes, Seay, Mattern & Mattern, Inc. (HSMM) 1315 Franklin Road

Roanoke, Virginia 24016 (540) 857-3279

(540) 857-3296 (fax) smcdowell@hsmm.com

and

Gibson V. Barbee, PE

Norfolk Southern Railway Company (NS) Environmental Protection Department

110 Franklin Road, Box 13 Roanoke, Virginia 24042-0013

(540) 981-5185 (540) 981-4651 (fax)

gvbarbee@nscorp.com

Removal of Petroleum Using Dual Phase Extraction

A. Scott McDowell, MS, REM - Hayes, Seay, Mattern & Mattern, Inc. (HSMM)

and

Gibson V. Barbee, PE - Norfolk Southern Railway Company (NS)

ABSTRACT

Railroad mechanical facilities handle significant quantities of petroleum hydrocarbon products including diesel fuel, lubricating oils, hydraulic oil, gasoline, and heating oil. This paper is focused on recovery and remediation of petroleum hydrocarbons at railroad mechanical facilities from the subsurface using a remedial technique referred to as “Dual Phase Extraction”. Dual Phase Extraction (DPE) is a remedial technique where strong vacuums (up to 29 inches of mercury) are applied to the subsurface through screened recovery wells. The technique is referred to as “Dual” Phase Extraction because it simultaneously removes vapors and fluids (groundwater and free phase petroleum hydrocarbons or Free Product – FP). DPE combines the effectiveness of Soil Vapor Extraction (SVE) and pump and treat. DPE has proven to be particularly effective in recovering free phase petroleum hydrocarbons. DPE achieves additional remedial action in the form of removal of the volatile organic fractions of vapors and introduction of oxygen to the subsurface thus enhancing biodegradation and natural attenuation. This paper reviews the technological aspects of DPE, presents environmental data from case studies at railyard sites, provides costs of DPE treatment for removal of FP on a per gallon basis and removal of total petroleum hydrocarbons on a per pound basis, and summarizes the economics of DPE versus alternative remedial options. Based on the data presented from three case studies showing mass of petroleum hydrocarbons removed in the free product phase, dissolved phase, and vapor phase; it is concluded that for heavy end low volatile fraction petroleum hydrocarbons at railroad mechanical facilities, the majority of petroleum is removed in the free product phase and that DPE is cost effective on a per mass basis in comparison to other technologies.

Removal of Petroleum Using Dual Phase Extraction

One of the best available technologies for treating saturated levels of petroleum hydrocarbons

that have reached the groundwater table is Dual Phase Extraction (DPE). DPE has also been

referred to as Mobile Enhanced Multi-Phase Extraction (MEME), Liquid Ring Extraction

(LRE), and bioslurping.

This paper presents per gallon costs to remove free phase petroleum hydrocarbons or Free

Product (FP) and per pound costs to removal total petroleum hydrocarbon mass from the

subsurface from three sites where DPE was applied. We will demonstrate that DPE is cost

effective and that the majority of the petroleum hydrocarbon mass will be removed as FP in

the case of heavy end petroleum hydrocarbons such as the mixture of diesel fuel, lubricating

oil, hydraulic oil, and gear oils most often encountered at railroad mechanical facilities.

DUAL PHASE EXTRACTION PROCESS

Dual Phase Extraction (DPE) applies a high vacuum on the subsurface soil and groundwater

(up to 29 inches of mercury) to remove a combination of vapor phase and liquid phase

petroleum hydrocarbons. The liquid phases consists of free phase petroleum hydrocarbons or

Free Product – FP and groundwater. Different pump arrangements can be used but the most

popular technology is what is referred to as a Liquid Ring pump. The liquid ring pump uses a

cylindrical chamber filled with liquid with an offset impeller to create strong vacuums.

DPE removes three phases of petroleum (free phase, dissolved phase, and vapor phase) with

the liquid phases entrained in vapors. The entrainment of fluids in vapor alleviates some

physical problems associated with fluid flow including friction and head that would preclude

pulling fluids past a theoretical maximum of approximately 30 feet in depth. DPE has been

reported to be effective to depths of up to 100 feet without a booster pump.

The DPE system can be configured in many different set-ups including manifolding to

multiple wells, running piping underneath railroad tracks to avoid fouling tracks and going

under fueling racks, and mobile containment and power can be supplied for inactive or remote

sites. DPE systems can be either a permanent fixed system or a mobile temporary system. A

typical, temporary DPE system can be installed within a standard 14-20 foot cargo trailer and

can fit in most railyard areas.

FREE PRODUCT FLOW IN THE SUBSURFACE

FP in the subsurface is a result of saturated conditions in the soil. Therefore, migration of FP

in the subsurface does not follow the same hydraulic principles of fluid flow under

atmospheric conditions. FP tends to be highly variable in terms of thickness and migration

patterns and can be present in a well one day and disappear the next. FP levels change

drastically with fluctuating groundwater tables tending to be thicker with a lower groundwater

table and thinner with a higher groundwater table. FP tends to move in “bubbles” as opposed

to evenly spaced layers. The highly variable nature of FP flow is a major factor that makes

the effectiveness of conventional FP removal technologies difficult to predict.

FP in the subsurface is difficult to remove because: (1) groundwater table levels fluctuate

resulting in highly variable FP levels and thicknesses, (2) the constituents of petroleum

hydrocarbons tend to adhere to soils by chemical forces and because viscous hydrocarbons are

bound in small pore spaces by capillary forces, and (3) FP often exists in low permeability

geologic conditions where fluid flow is limited.

DPE can overcome these problems because: (1) a drop tube arrangement can be easily

positioned to adjust to the fluctuating groundwater table, (2) the strong vacuum assists in

detaching constituents from soils, and (3) the strong vacuum provides increased well yields

(2-4 times greater than conventional pumping) in low permeability formations.

DPE also provides additional treatment in the form of aeration of the subsurface, including the

zone below the normal saturated groundwater level when the groundwater table is depressed.

Aerating the subsurface transfers the volatile fraction of hydrocarbons to the vapor phase and

provides oxygen for biodegradation. In fact, DPE systems can treat localized gasoline

releases in as little as a few days or weeks as the large volatile portion of gasoline is readily

removed. However, for railroad mechanical facilities, the petroleum products tend to be

heavier end (long chain) hydrocarbons associated with diesel fuel, lubricating oil, hydraulic

oil, and gear oil. High molecular weight petroleum hydrocarbons are less volatile and are less

mobile. Therefore, depending on the goals of the corrective action, longer treatment times

may be required, in the range of months to years.

Unlike most remedial technologies that treat one media (e.g., soil), DPE removes FP,

dissolved groundwater constituents, and vapors, as well as treating residual concentrations in

soils. It is this multiple effect in combination with the flexibility of the mobile, temporary

system that makes DPE such an effective and popular technology.

DPE can be configured in temporary or permanent remedial systems, but the most cost

effective method is a mobile trailer-mounted temporary system. The temporary system can be

operated for as short or as long a period as necessary. The DPE system can be operated by a

single person or operated automatically with periodic maintenance checks. The largest cost in

any remedial system tends to be labor, as opposed to equipment and materials. A DPE system

can be operated for as little as $5,000 per week, including operation and maintenance, power

source, labor, and documentation of operating conditions and data from observation wells.

The DPE system can use almost any standard monitoring well (2-inch diameter or greater) as

an extraction well and this is another positive cost saving feature in that system specific wells

or subsurface piping are not required.

LIQUID AND VAPOR DISCHARGE

An important question in any groundwater remedial system is how the extracted fluids will be

handled. Many railyards have on-site wastewater pre-treatment plants designed to handle oily

wastewater to which extracted groundwater can be discharged. The recovered FP must be

contained and handled separately or added to on-site oil recycling volumes. If on-site

wastewater treatment is not available, direct discharge to sanitary sewer systems (meeting

pretreatment requirements) or discharge to Underground Injection Control (UIC) infiltration

trenches are options. Further treatment or polishing steps can be added to meet discharge

requirements and may include oil/water separation, Granular Activated Carbon (GAC), or

small biologically activated sludge treatment steps (with contact time of 5-10 hours). Direct

discharge to surface waters is possible but a National Pollutant Discharge Elimination System

(NPDES) permit will be necessary and may take considerable time and effort, if a general

permit for remediation activities is not available from the local wastewater treatment

authority.

Because DPE discharges vapors containing petroleum hydrocarbons, potential emissions

should be evaluated to determine the need for an air permit. Air discharge permits are

generally not necessary for heavy end fuel treatment due to the low component of VOCs.

However, this depends on thresholds in local and state regulations. Although emission

controls may not be required by regulatory agencies, strong odors can be a nuisance near

residential areas or areas frequented by facility personnel.

DPE treatment of high VOC component fuels such as gasoline will often require air discharge

permits and/or treatment of off-gases. Use of automated systems can minimize exposure to

vapors. Flash point analysis on extracted groundwater may be necessary to ensure that

discharged groundwater does not exhibit the characteristic of ignitability under the Resource

Conservation and Recovery Act (RCRA).

SYSTEM EFFECTIVENESS

Table 1 presents data from three case histories of DPE FP removal at railroad mechanical

facilities. The effectiveness of the DPE system can be evaluated by the estimated cost of

recovery per gallon of free phase petroleum hydrocarbons or Free Product (FP) or cost of

removal per pound of total petroleum hydrocarbon mass including FP, dissolved, and vapor

phases.

The total estimated cost per gallon of FP recovered for Site 1, Phase I (pilot phase) was $290

per gallon and $40 per pound of hydrocarbon. This cost included pilot testing of an additional

5 extraction wells where FP recovery was minimal. Dissolved phase and vapor phase

removals were not estimated for these wells and the estimated cost per pound of hydrocarbon

removed is therefore conservative. Also, mass of hydrocarbons removed by biodegradation is

not included in the calculation. Even considering the pilot phase where several wells treated

did not produce effective hydrocarbon removal, the estimated cost of DPE was about $290 per

gallon of FP recovered as compared to manual bailing which was estimated at about $400 per

gallon or more. In general, manual bailing was labor intensive with minimal FP recovery at

Site 1.

For Site 1, Phase II, the estimated cost dropped to $91 per gallon FP recovered and $13 per

pound total hydrocarbons. The reduction in cost was due to targeting only wells where FP

recovery was expected to be effective and the cost economy achieved by changing to a lower

monthly contract rate for DPE treatment as opposed to a daily cost.

For Site 2, the estimated cost of DPE treatment was $268 per gallon of FP and $26 per pound

hydrocarbon.

For Site 3, the estimated cost of DPE treatment was $23 per gallon FP and $3 per pound

hydrocarbon removed. Clearly, DPE was highly effective at Site 3 and FP recoveries were

much greater (total of 3,390 gallons of FP recovered). The reason for the greatly increased

effectiveness of DPE at Site 3 is apparently due to the relatively homogenous high

permeability sandy geology. The estimated hydraulic conductivities for Sites 1 and 2 were in

the 0.16 to 2.5 feet per day. The estimated hydraulic conductivity for Site 3 was 150 feet per

day. Sites 1 and 2 consisted mainly of relatively impermeable clayey silts with natural and

man-made heterogeneity. Site 3 consists of fine to medium grained sands along a major river

flood plane that were much more homogeneous than Sites 1 or 2. It appears that the

combination of homogeneity allowing a relatively even radius of influence and high

permeability allowing mobilization of FP for Site 3 resulted in much higher FP recoveries.

The low organic content soils (silicon based sands), may also have allowed easier detachment

of petroleum constituents than high organic content soils where large molecular weight

petroleum constituents tend to adhere to soil particles.

Table 1 also shows that mass recoveries in the FP phase are much more significant than the

dissolved phase and the dissolved phase is generally much greater than the vapor phase

(except for Site 2 where the airflows were in the 50-60 scfm range). Keep in mind that the

vapor removal rates for these case studies are based on heavy end petroleum hydrocarbons at

railroad mechanical facilities where the volatile content is much lower than gasoline.

Reportedly, DPE treatment of gasoline releases often removes the largest mass of petroleum

via the vapor phase.

RECOVERY OF FREE PRODUCT AS A FOCUS OF CORRECTIVE ACTION

A major omission in many remedial projects (and models of contaminant mass and migration)

is the FP phase. Table 1 shows that, without taking into account the FP phase, the mass of

petroleum might be vastly under estimated. Migration of FP is extremely difficult to predict

and FP thicknesses in groundwater monitoring wells and migration pathways vary widely

with fluctuating groundwater table levels, recharge events, and natural and man-made

migration pathways. In addition, treatment of soil below the saturated zone or constituents

dissolved in groundwater is not technically feasible or cost effective without removal of FP

because the FP will continue to contaminate the residual soil and dissolved groundwater

phases. This was one major downfall of past attempts at pump and treat and soil venting type

remedial systems. Table 1 shows without a doubt that removal of groundwater only would

result in minimal remediation of petroleum. The major advantage of DPE is that it combines

the most effective method of FP recovery with soil venting, groundwater extraction, and

enhanced biodegradation. Note that the above estimates of DPE effectiveness do not take into

account any biodegradation that is probably occurring.

Although DPE is designed to be effective on low permeability formations, it appears from the

Site 3 data that the high permeability formation at Site 3 contributed to excellent FP recovery.

Of course, relative homogeneity and relatively high permeability will increase effectiveness

of almost any subsurface remediation system.

Two wells at Site 1 showed poor FP recovery that may be due to heterogeneity of the

formation around these extraction wells. DPE has been shown to be effective in most

situations, but there are wells where other technologies are more appropriate. Alternative

technologies include oil belt skimmers, dual pumping systems, hydrophobic screens,

skimmers, and suction systems such as Swap™.

Other petroleum removal systems may have a lower cost per gallon or per pound for

petroleum removal. Oil belt skimmers, hydrophobic screens, and dual pumping systems

operate in the $20 to $100 per gallon FP removal range. However, FP will not be mobilized

by vacuum, no vapors will be removed, no dissolved phase will be remediated, and no oxygen

will be introduced to the subsurface to enhance biodegradation. Therefore, if DPE is

comparable in cost to alternative remedial systems, it would seem a straightforward

conclusion to apply DPE if pilot testing indicates that DPE will remove significant FP.

PERMANENT VERSUS TEMPORARY SYSTEMS

A temporary, mobile trailer mounted DPE system costs approximately $5,000 to $10,000 per

5-day working week to operate. A permanent system connected to 4-6 wells costs

approximately $50,000 to $100,000 to construct. At a minimum, pilot phase and extended

temporary DPE testing data should be gathered and evaluated prior to designing, costing, and

implementing a permanent system. Temporary systems have the following advantages: (1)

they can be demobilized as soon as treatment has been successful, thus reducing overall costs,

(2) mobile systems can be operated with diesel powered generators in remote locations (or

inactive facilities with no power source), (3) mobile systems keep a lower profile and do not

leave any permanent piping that must be removed, (4) temporary systems can be combined

with mobile discharge containment systems for remote locations, (5), temporary systems are

more flexible (e.g., can be manifolded to different wells at different times depending on recent

feedback), and (6) temporary systems are usually operated by contractors who are responsible

for all operation and maintenance and potential liability (e.g., spills, health and safety).

However, at some point of time of DPE treatment, a permanent system becomes more cost

efficient than a temporary system. The unknowns are how much FP will be recovered and

how long will it take to recover the FP. It is difficult to estimate the total mass of

hydrocarbons in a site, although it can be done based on average concentrations in soil, vapor,

and groundwater over a specific area.

PULSED OR INTERMITTENT DPE TREATMENT VERSUS CONTINUOUS

DPE TREATMENT

There is conflicting opinion on whether pulsed or intermittent DPE treatment is more

effective than continuous DPE treatment. On the one hand, continuous DPE treatment may

be necessary to achieve a large cone of groundwater depression, a maximized radius of vapor

influence, maximized “detachment” of constituents from soils, and to mobilize FP to the

extraction well. One contractor indicated that the best DPE method is long term, continuous

treatment. Another theory is that “pulsing” allows the groundwater table to recover, thus

dissolving more hydrocarbons from the residual (soil) phase, in effect intermittently

dewatering and rewetting the upper saturated zone thus “washing” the uppermost groundwater

table where most of the petroleum hydrocarbons exist. One contractor indicated that

continuous treatment is not necessary.

A recent communication from the Virginia Department of Environmental Quality (DEQ)

stated that, “Pulse application of Dual Phase Extraction (DPE) should not be utilized. Current

information indicates that pulsed operation does not improve, and actually hinders, product

recovery from the vadose zone. Product in this zone is sorbed to soil particles and is

generally only mobilized by vapor transfer that occurs after dewatering. Pulse operation that

re-wets this zone requires repeated de-watering before transfer can be realized. It is therefore

recommended that DPE operation be continuous.”

Another consideration is that DPE is associated with enhanced biodegradation of the

dewatered zone due to introduction of oxygen. Pulsing may “hinder” enhanced

biodegradation.

The above statement that “…FP in this zone is sorbed to soil particles and is generally only

mobilized by vapor transfer that occurs after dewatering..” appears to be addressing

petroleum with a high percentage of Volatile Organic Compounds (VOCs), such as gasoline.

Many contractors treat gasoline releases to the subsurface with DPE by vaporizing the

majority of the petroleum mass, with little or no FP recovery. Heavy end, long chain

hydrocarbons, such as diesel fuel and lubricating oils most common at railroad mechanical

facilities behave much differently from lighter end high percentage VOC content fuels. The

composition of the type of constituents being treated should always be considered in the

system design for mechanical as well as safety reasons (e.g., high percentage VOC

constituents can present flammability and/or explosivity issues). Treatment of heavy end

petroleum hydrocarbons using DPE is probably based on physical forces to remove FP more

than vaporization and/or biodegradation.

An important part of the equation is risk assessment. Risk based corrective actions may focus

on removal of FP and dissolved constituents whereas treatment of the vadose, or unsaturated

zone, may be considered to present a lower risk to human health and the environment.

DESIGN CONSIDERATIONS

A basic trailer-mounted DPE system should have the following components: air flow

minimum capacity of 100 scfm, capability to pull at least 25 inches Hg, mobile diesel

generator capable of providing 3-phase power, Oil Water Separator (OWS), containment tank,

site glass on phase separation tank, and butterfly valves to control vacuum to wells.

Additional items may include: extraction groundwater discharge steps (GAC or activated

sludge), air treatment steps (GAC, catalytic oxidizers, or biofilter), and remote operation and

automatic shut off valves. Secondary containment may also be appropriate in some cases.

Note that in most cases, a high vacuum results in lower airflows and the converse is true –

high airflows result in low vacuums. The optimal vacuum and airflow should be determined

for each specific site.

When wells are within 100 feet distance and no obstructions exist, efficiency can be gained by

manifolding wells together.

WAYS TO IMPROVE THE SYSTEMS

Improvements to an existing DPE basic system could include:

ü built in diesel power

ü explosion proof equipment

ü more energy efficient power generation

ü increased remote/automated operation capability to reduce labor costs and improve

safety

ü minimized size to access more limited spaces

ü installation of additional extraction wells to improve FP removal and overall treatment

ü use with hydraulic or pneumatic fracturing in extremely low permeability formations

ü positioning drop tube to minimize groundwater extraction if appropriate

CONCLUSION

DPE is an extremely effective method for removing FP from the subsurface and treating

petroleum hydrocarbons in the residual and dissolved phases. DPE is a very popular

technology at this time due to its cost effectiveness and flexibility in operation in comparison

with other technologies. Data gathered from the case studies presented here indicate that DPE

can be very successful in removing FP in high permeability, relatively homogeneous

formations. DPE combines the physical and chemical affects of groundwater withdrawal,

vapor extraction, and enhanced biodegradation of residual phase by introduction of oxygen.

A pilot phase is necessary in order to eliminate extraction wells where DPE will not be

successful and to determine design requirements for full-scale implementation. A pilot phase

of at least 2-4 days is recommended.

The jury is still out on whether continuous or pulsed operation is more beneficial, but

regulatory guidance indicates that continuous treatment is the preferred method.

Considerations of potential flammability and explosivity of vapors should be taken into

account. Gasoline recovery systems produce large volumes of vaporized VOCs and may be

operated remotely for safety reasons. Flash point testing for extracted groundwater is

recommended before discharging. Good coordination with on-site or off-site wastewater

pretreatment coordinators is critical. Calculations of estimated vapor discharge

concentrations should be compared to local air discharge regulations to determine if air

permitting may be necessary.

The state and federal environmental regulations are clear that removal of free phase petroleum

hydrocarbons is required. Federal regulations under 40 CFR 280.64 contain the following

statement, “…owners and operators must remove free product to the maximum extent

practicable…”. Regulations regarding residual and dissolved phase constituents allow risk

based corrective action. Therefore, based on regulatory guidance and technical necessity to

remove a source of continuing impact to soil and groundwater, it is sensible to focus efforts

on removal of FP. In general, “risk based” corrective action should include removal of

sources and areas of concentrated Constituents of Concern (CoCs) or “hotspots”, of which FP

is a good example.

We have demonstrated that DPE is cost effective at a range of $23 to $290 per gallon of free

product or $3 to $40 per pound total hydrocarbons in comparison to other technologies. Our

data also demonstrates that the greatest petroleum mass removal is in the FP phase for heavy

end petroleum hydrocarbons at railroad mechanical facilities. Manual hand bailing of FP is

not considered to be cost effective. Other FP removal techniques including oil belt skimmers,

dual pumping systems, suction systems such as Swap™, and hydrophobic screens can be

effective. However, maintenance and labor costs can be significant and FP recovery can be

disappointing.

Removal of FP prior to considering remediation of dissolved groundwater and residual soil

phases is a principle that makes sense. Considering that one gallon of FP can contaminate

somewhere on the order of a million gallons of groundwater or more, there is no question that

an investment of $20 to $300 per gallon to remove FP is reasonable. Our experience

indicates that without removal of FP, remedial systems are costly and long-term effectiveness

is questionable.

In general, success of remedial projects begins with identifying achievable goals. An

achievable goal is removal of FP and risk based natural attenuation of the remaining residual

and dissolved phase constituents. DPE technology reflects an improvement in remedial

technology. Combining DPE with risk based and natural attenuation approaches is resulting

in more practical, more cost effective, and more reasonable remedial actions.

Acknowledgements

Hayes, Seay, Mattern & Mattern , Inc. (HSMM) would like to thank Norfolk Southern

Railway Company (NS) for the opportunity to work with them on many excellent projects

including the Dual Phase Extraction (DPE) work that provided the data that is the heart of this

paper. I would also like to thank Mr. Troy Kincer and everyone in HSMM Environmental

Division for their tireless efforts and positive attitude.

Figure 1 shows a cross section of a typical DPE treatment system and illustrates the vadose

(unsaturated) zone, groundwater table with cone of depression, radius of vacuum influence,

sources of heterogeneity, and the fact that free product exists in the subsurface in pockets of

saturated soils and groundwater as opposed to layers.

TABLE 1

Results of Dual Phase Extraction for 3 Sites

Comparison of Cost per Gallon of Free Product Recovered and Cost per Pound Petroleum Removed

Hayes, Seay, Mattern & Mattern, Inc. (HSMM) and Norfolk Southern Railway Company (NS)

AREMA Conference 2001 SITE 1

Phase 1 SITE 1 Phase II

SITE 1 Manual Bailing

SITE 2 SITE 3

Total FP Recovered (gallons)

129 262 50 gallons per year 149 3,390

Total FP Mass (lb) 890 1,808 345 1,028 23,395

Total GW Extracted (lb)

13,085 8,172 0 32,406 9,900

Total GW Petroleum Mass (lb)

37 8.6 345 147 264

Total Petroleum Vapor Removed (lb)

0.3 0.6 0 338 59

Total Petroleum Mass Removed (lb)

927 1,817 345 1,513 23,718

Total Cost $ $37,443 (a)

$23,862 (b)

$20,000 $40,000 (c) $76,400 (d)

Total Cost/gallon $290 $91 $400 $268 $23

Total Cost/lb $40 $13 $58 $21 $3 (a) Cost includes treating 5 wells where FP recovery was minimal in pilot test phase (10

wells, 24 hours total treatment) (b) Monthly contract costs were lower than daily costs and Phase I pilot costs (4 wells, 10

days per well, 24 hours per day) (c) 24-hour per day DPE treatment (4 wells, 5 days per well, 24 hours per day) (d) 7 wells, total of 120 hours per well

List of Tables

Table 1 Results of Dual Phase Extraction for 3 Sites Comparison of Cost per Gallon of Free Product Recovered and Cost per Pound Petroleum Removed

List of Figures

Figure 1 Cross Section of Dual Phase Extraction (DPE) Application