An Assessment of Oil Shale Technologies (Part 10 of 18)

CHAPTER 8

Environmental Considerations

PageIntroduction . . . . . . . . . . . . . . . . . . . . . ......255

Summary of Findings . ...................256Air Quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . 256Water Quality. . . . . . . . . . . . . . . . . . . . . . . . . .256Occupational Health and Safety . ..........257Land Reclamation. . . . . . . . . . . . . . . . . . . . . ..258Permitting. . . . . ........................259

Air Quality . . . . . . . . . . . . . . . .. ... ... .+ ...259Introduction . . . . . . . . . . . . . . . . . . . . . ......259Pollutant Generation . . ..................259Air Quality Laws, Standards, and Regulations 263Air Pollution Control Technologies . ........269Pollutant Emissions. . . . . . . . . . . . . . . . . . . . . .278Dispersion Modeling. . ...................279A Summary of Issues and Policy Options. ....288

Water Quality. . . . . . . . . . . . . . . . . . . . . . . . . .291Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 29lPollution Generation. . . . . . . . . . . . . . . . . . . . . 292Summary of Pollutants Produced by Major

Process Types. . . . . . . . . . . . . . . . . . . . . . . .294Effects of Potential Pollutants on Water

Quality and Use. . . . ...................295Water Quality in the Oil Shale Region. .. ....296Water Quality Regulations. . ..............297Technologies for Control of Oil Shale Water

Po l lu t ion . . . . . . . . . . . . . . . . . . . . . . . . . . . . 304Ultimate Disposition of Waste Water . .......308Monitoring Water Quality . ...............309Information Needs and R&D Programs .. ....311Findings on Water Quality Aspects of Oil

Shale Development. . . . . ...............314

P a g e

Policy Options for Water Quality Management 314

Safety and Health. . . . . . . ................315Introduction . . . . . . . . . . . . . . . . . . . . . ......315Safety and Health Hazards . ..............316Summary of Hazards andTheir Severity. ....322Federal Laws, Standards, and Regulations. ..324Control and Mitigation Methods . ..........325Summary of Issues and R&D Needs . . . . . . . . . 326Current R&D Programs. . .................326Policy Considerations. . ..................327

Land Reclamation. . . . . . . . . . . . . . . . . . . . . . .328Introduction . . . . . . . . . . . . . . . . . . . . . ......328Reasons for Reclamation . ................329Regulations Governing Land Reclamation. ...329Reclamation Approaches. . ...............330The Physical and Chemical Characteristics

of Processed Shale . . . . . . . . . . . . . . .. ....332Use of Topsoil as a Spent Shale Cover . ......335Species Selection and Plant Materials . . . . . . . 336Review of Selected Research to Date. .......339Summary of Issues andR&D Needs . . . . . . . . . 341Policy Options for the Reclamation of

Processed Oil Shales. . .................342

Permitt ing . . . . . . . . . . . . . . . . . . . . . . . . . . . . .343Introduction . . . . . . . . . . . . . ..............343Perceptions of the Permitting Procedure. ....344Status of Permits Obtained by Oil Shale

Developers . . . . . . . . . . . . . . . . . . . .The Length of the Permitting ProcedureDisputes Encountered in the Permitting

Procedure . . . . . . . . . . . . . . . . . . . . .

0 . , . . 345. , , . . 346

. . . . . 346

PageUnresolved Issues. . .....................347Attempts at Regulatory Simplification. .. ....348Policy Options. . . ..............,.,....,.349

Chapter8 References. . ..................352

List of Tables

TableNo, Page34.

350

36.

37.

38.

39.

40.

41.

42.43.

44.

45,

46.

47.

48.

49.

50.

51.

52.

53.

Pollutants Generated bythe ColonyDevelopment Project . . . . . . . . . . . . . . . . 262PollutantsGenerated by the Rio BlancoProject on TractC-a. . . . . . . . . . . . . . . . . 263Pollutants Generatedbythe OccidentalOperation on TractC-b . . . . . . . . . . . . . . 263The Federal and State Ambient AirQuality Standards and Prevention ofSignificant Deterioration StandardsThat Influence Oil Shale Development . . 266National Standards for Prevention ofSignificant Deterioration of AmbientAir Quality, . . . . . . . . . . . . . . . . . . . . . . . 267National New Source PerformanceStandards for Several Types of Facilities 269EPA Standards for Best Available AirPollutionControl Technologies for OilShale Facilities. . . . . . . . . . . . . . . . . . . . . 269Technological Readinessof Air PollutionControl Technologies . . . . . . . . . . . . . . . . 276Costs of AirPollutionControl . . . . . . . . . 277Pollutants Emitted by theColonyDevelopment Project . . . . . . . . . . . . . . . . 278Pollutants Emitted by theRio BlancoProject on Tract C-a. . . . . . . . . . . . . . . . . 278Pollutants Emitted by the OccidentalOperation on TractC-b . . . . . . . . . . . . . . 279ASummary of Emission Rates From FiveProposed Oil Shale Projects. . . . . . . . . . . 279A Comparison of Atmospheric EmissionsUsed in Modeling Studies. . . . . . . . . . . . . 282Modeling Results for Federal Oil ShaleLease TractC-a . . . . . . . . . . . . . . . . . . . . 284Models Used in SupportofPSDApplications for Oil Shale Projects . . . . . 285Areas of Inadequate Information andSuggested R&D Responses . . . . . . . . . . . . 288Generation Rates for Principal WaterPollutants for Production of 50,000 bbl/dof Shale Oil Syncrude. . . . . . . ..., . . . . . 294Quality of Some SurfaceStreams in theOil Shale Region . . . . . . . . . . . . . . . . . . . . 297Quality of GroundWaterAquifers in thePiceance Basin. . . . . . . . . . . . . . . . . . . . . 297

Page54. Effluent Limitations for Petroleum

Refineries Using BestPracticablePollution Control Technology. . . . . . . . . . 299

55. Effluent Limitations for Best Available

56

57

Technology Achievable for PetroleumRefinery Facilities . . . . . . . . . . . . . . . . . . 299New Source Performance Standards forPetroleum Refineries . . . . . . . . . . . . . . . . 300Colorado Water Quality Standards forStream Classification B2 . . . . . . . . . . . . . 301

58. Utah Water Qualitv Standards for

59

6061

Stream Classification CW . . . . . . . . . . . . 301Proposed Water Quality Criteria forDesignated Uses. . . . . . . . . . . . . . . . . . . . 302Primary Drinking WaterStandards . . . . 303Proposed Secondary Drinking WaterRegulations. ,.. .. ~.. .., ..~.... . . . . . 303

62. The Types of Contaminants in Oil ShaleWastewater Streams and Some PotentialProcesses for RemovingThem . . . . . . . . . 305

63. Relative Rankings of the Water

64.

65,

66.

67.

68.

69.

70.

Treatment Methods . . . . . . . . . . . . . . . . . 306Estimated Costs of Water PollutionControl in Oil ShalePlants. . . . . . . . . . . . 306Sampling Schedule Summary for Surfaceand Ground Water Monitoring Programat Tract C-b During Development Phase. 312Animal Studies on the Carcinogenicity ofOil Shale and ShaleOil . . . . . . . . . . . . . . 320Benzo(a)pyrene Content of 0il Shale andIts Products and of Other EnergyMaterials . . . . . . . . . . . . . . . . . . . . . . . . . 320The Chemical and Physical Properties ofProcessed Shales . . . . . . . . . . . . . . . . . . . 332Estimates of Reclamation Needs UnderVarious Levels of Shale Oil Production. , 338Status of the Environmental Permits forFive Oil Shale Projects, . . . . . . . . . . . . . . 345

List of Figures

59. Designated Class I Areas in Oil Shale PageRegion . . . . . . . . . . . . . . . . . . . . . . . . . . . . 268

60, Computation Modules in AtmosphericDispersion Models . . . . . . . . . . . . . . . . . . 281

61. An Aboveground Spent Shale DisposalArea . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307

62. Summary of Occupational HazardsAssociated With Oil ShaleDevelopment. 323

CHAPTER 8

Environmental Considerations

IntroductionThe region where oil shale development

will take place is, at present, relatively un-disturbed. The construction and operation ofplants would emit pollutants and producelarge amounts of solid waste for disposal. Asa consequence, air, water, and soil could bedegraded and the topography of the landcould be altered. The severity of these im-pacts will depend on the scale of the opera-tions and the kinds of processing technologiesused, as well as the control strategies thatmust be adopted to comply with environmen-tal regulations.

Control strategies have been proposed forpurifying water and airborne emissionsstreams, for revegetation, for protecting wild-life, and for other specific areas of envi-ronmental concern. However, control tech-nologies that are applied to one area couldadversely affect another area. For example,to control air pollution, airborne streams arescrubbed to capture dust and gaseous con-taminants. This produces sludges and waste-water that have to be disposed of along withother wastes. All of these have the potentialto adversely affect the land and the water.

Airborne pollutants, such as trace metals,might enter surface streams and groundwater in fugitive dust and or rainfall andcould alter the chemical and biological bal-ances of the water systems. Plant and animallife as well as human health could be harmedboth by an increase in water contaminationand by the entry of the contaminants into thefood chain. Similarly, without adequate con-trols, the piles of solid waste could contami-nate the air and water through fugitive dust

emissions and by the leaching of soluble con-stituents into surface and ground water sys-tems. Water quality could thus be degradedby altered nutrient loading, changes in dis-solved oxygen, and increased sediment andsalinity.

For these reasons, each potential environ-mental effect along with its control technol-ogy should be examined with respect to its netimpact on the total environmental system. Todo this requires full understanding of theseparate impacts on air, water, and land, theinteraction between the individual parts ofthe ecosystem, and the efficacy of the controlstrategies. Such an analysis needs a completeand accurate data base which is as yet un-available because no commercial oil shaleplants have been built. OTA’s environmentalanalysis, therefore, is limited to examiningthe effects that an oil shale industry wouldhave on the separate areas of air, water,land, and occupational health and safety. Inorder to provide a basis for policy analysis,the effects are quantified wherever possibleand related to a production of 50,000 bbl/d.For each of the areas examined:

impacts of oil shale operations are de-scribed;applicable laws and regulations aresummarized, and their significance to oilshale analyzed;control strategies proposed for compli-ance with the laws and regulations aredescribed and evaluated; andpolicies that could be focused on key is-sues and uncertainties are identifiedand discussed.

255

256 ● An Assessment of Oi/ Shale Technologies

SummaryAir Quality

Because of the oil shale region’s rural character,

i t s a i r i s r e l a t i v e l y c l e a n a n d u n p o l l u t e d . O c c a s i o n a l -

l y , h o w e v e r , h i g h c o n c e n t r a t i o n s o f h y d r o c a r b o n s

( p o s s i b l y f r o m v e g e t a t i o n ) a n d p a r t i c u l a t e f r o m

w i n d b l o w n d u s t occu r . The development of a large o i l

s h a l e i n d u s t r y ( o r a n y i n d u s t r i a l o r m u n i c i p a l g r o w t h )

w i l l d e g r a d e t h e a i r ’ s v i s i b i l i t y a n d q u a l i t y . E v e n i f

the best ava i lab le cont ro l technolog ies a r e u s e d a n dcompliance is maintained with the provisions of theClean Air Act, its amendments, and the applicableState laws, degradation will occur. It will take placenot only near the oil shale facilities but also in nearbypristine areas (e.g., national parks, wildernessareas). Some places may be affected more thanothers from local concentrations of pollutants causedby thermal inversions.

Findings of the analysis include:

● Oil shale mining and processing will produce at-mospheric emissions including those pollutantsfor which National Ambient Air Quality Standards(NAAQS) have been established (i.e., sulfur diox-ide, particulate, carbon monoxide, ozone, lead,and nitrogen oxides); as well as various other cur-rently unregulated pollutants (such as silica,sulfur compounds, metals, trace organics, andtrace elements).

● Under the Clean Air Act, oil shale development willhave to comply with NAAQS and State air qualitystandards; maintain air quality, especially visibili-ty, in adjacent Class I areas (e.g., national parks);comply with prevention of significant deterioration(PSD) increments (these specify the maximum in-creases in the concentrations of sulfur dioxide andparticulate that can occur in any region); complywith New Source Performance Standards (NSPS);and apply the best available control technology(BACT).

● A wide variety of control technologies could be ap-plied to the emissions streams from oil shale proc-esses. They are fairly well developed and havebeen successfully used in similar industries. Theyshould be adaptable to the first generation of oilshale plants. However, full evaluation will not bepossible until they have been tested in commer-cial-scale oil shale plants for sustained periods.

of Findings●

●

●

The costs of controlling air pollution will be par-ticularly sensitive to the strictness of the environ-mental regulations and to the design characteris-tics and size of each project. Preliminary estimatesindicate that air pollution control could cost from$0.91 to $1.16/bbl of syncrude produced (rough-ly 3 to 5 percent of the selling price of the oil).

The only means for predicting the long-range im-pacts of oil shale emissions on ambient air qualityin the oil shale area and in neighboring regions aremathematical dispersion models, which are theEnvironmental Protection Agency’s (EPA) tool forenforcing the provisions of the Clean Air Act. Mod-eling of oil shale facilities presents a number ofproblems because of the topography and meteorol-ogy of the region, the chemistry of the emissions,and the unknown quantities of emissions expectedfrom commercial-size facilities. In addition, dis-persion models developed to date have been pri-marily for flat terrain. Thus, their predictions con-tain significant inaccuracies. More R&D needs tobe undertaken in this area.

Even with the use of BACT, the industry’s capacitywill be limited by the air quality standards govern-ing PSD. A preliminary modeling study by EPA hasindicated that an industry of up to 400,000 bbl/din the Piceance basin could probably comply withthe PSD standards for Flat Tops (a nearby Class Iarea) if the plant sites were dispersed. Additionalcapacity could be installed in the Uinta basin,which is at least 95 miles from Flat Tops, A 1-mil-lion-bbl/d industry could probably not be accom-modated because at least half of its capacity(500,000 bbl/d) would be located in the Piceancebasin. Policy options to address this limitation in-clude the application of more stringent emissionstandards, changes in PSD increment allocationprocedures, and amending the Clean Air Act.

Water Quality

Water quality is a major concern in the oil shale re-gion, especially in regard to the salinity and sedimentlevels in the Colorado River system. The potential forpollution from oil shale development could come from

Ch. 8–Environmental Considerations ● 257

point sources such as cooling system discharges;from nonpoint sources such as runoff and leaching ofaboveground waste disposal areas and ground waterleaching of in situ retorts; and from accidental dis-charges such as spills from trucks, leaks in pipe-lines, or the failure of containment structures, Un-less these pollution sources are properly controlled,the lowered quality of surface and ground waterresources could adversely affect both aquatic biotaand water for irrigation, recreation, and drinking.

Specific findings include the following:●

●

●

Surface discharge from point sources is regulatedunder the Clean Water Act, and ground water rein-fection standards are being promulgated under theSafe Drinking Water Act. Solid waste disposalmethods may be subject to the Toxic SubstancesControl Act and the Resource Conservation andRecovery Act. The general regulatory framework istherefore in place, although no technology-basedeffluent standards have been promulgated for theindustry under the Clean Water Act. Nonpointsources present regulatory and technological diffi-culties, and at present are subject to less stringentcontrols.

Developers are currently planning for zero dis-charge to surface streams and to reinject only ex-cess mine water. This eliminates point dischargeproblems because most wastewater will be treatedfor re-use within the facility, and untreatablewastes will be sent to spent shale piles. The costsof this strategy are low to moderate, and develop-ment should not be impeded by existing regula-tions if it is used.

A variety of treatment devices are available for theabove strategy, and many of them should be well--suited to oil shale processes. However, uncertain-ties exist regarding whether conventional methodswould be able to treat wastewaters to dischargestandards because they have not been tested withactual oil shale wastes under conditions that ap-proximate commercial production. There are also anumber of uncertainties regarding the control ofnonpoint pollution sources. For example, no tech-nique has been demonstrated for managingground water leaching of in situ retorts, nor hasthe efficacy of methods for protecting surface dis-posal piles from leaching been proven. It is notknown to what extent leaching will occur, but if itdid, it would degrade the region’s water quality.

● Although control of major water pollutants frompoint sources is not expected to be a problem, lessis known about the control of trace metals and tox-ic organic substances. Research is needed to as-sess their potential hazards and to develop meth-ods for their management. Other laboratory-scaleand pilot-plant R&D should be focused on charac-terizing the waste streams, on determining thesuitability of conventional control technologies,and on assessing the fates of pollutants in thewater system. Extensive work is already under-way; its continuation is essential to protectingwater quality, both during the operation of a plantand after site abandonment.

Occupational Health and Safety

The oil shale worker will be exposed to occupa-tional safety and health hazards. Many of these–such as rockfalls, explosions and fires, dust, noise,and contact with organic feedstocks and refinedproducts–will be similar to those associated withhard-rock mining, mineral processing, and the refin-ing of conventional petroleum. However, the workersmight be exposed to unique hazards due to the phys-ical and chemical characteristics of the shale and itsderivatives, the types of development technologies tobe employed, and the scale of the operations. Poten-tial risks include safety hazards that might result indisabling or fatal accidents, and health hazardsstemming from high noise levels, contact with irritantand asphyxiant gases and liquids, contact with likelycarcinogens and mutagens, and the inhalation of fi-brogenic dust.

Specific findings include:

●

●

Only a few fatalities have occurred during the min-ing of over 2 million tons of shale and the produc-tion of over 500,000 bbl of shale oil. The accidentrate has been one-fifth that for all mining, andmuch lower than that for coal mining. However,this record was achieved in experimental minesthat employed, for the most part, experiencedminers. Whether safety risks will increase or de-crease as mining activities are expanded cannotbe predicted.

Although the carcinogenicity of oil shale dusts andcrude shale oil has been demonstrated by some in-vestigators, the conflicting results of other studiescombined with an overall lack of information pre-

258 ● An Assessment of Oil Shale Technologies

●

●

●

elude a determination of the severity of the risk.The incidence of diseases in other industries indi-cates that exposure to these materials could behazardous.

The large variety of substances that will be en-countered in retorting may present as yet unde-tected health hazards. Of special concern is thepossibility of carcinogens in shale oil and its de-rivatives, Possible synergistic effects from theproducts of modified in situ (MIS) operations(which combine mining with retorting) could in-crease the level of risk.

Shale oil refining poses no special hazards sincemost of its problems will be similar to those experi-enced in conventional petroleum refining.

Health and safety hazards will be reduced byusing pollution control technologies for air andwater pollutants and by requiring specific indus-trial hygiene practices. These are required by lawand are expected to be implemented by oil shaledevelopers. However, it is essential that R&D onthe nature and severity of health effects keep pacewith the development of the industry. Such infor-mation will be useful in identifying and mitigatinglong-term effects on workers and the public.

Land Reclamation

An industry will require land for access to sites,for the facilities, for mining, for retorting, for oilupgrading, and for waste disposal. The extent towhich development will affect the land on and near agiven tract will be determined by the location of thetract; the scale, type, and combination of processingtechnologies used; and the duration of the opera-tions. The facilities must comply with the laws andregulations that govern land reclamation and wastedisposal. Nevertheless, there will still be effects onland conditions (through altered topography) andwildlife (through changes in forage plants and habi-tats). In addition, unless appropriate disposal andreclamation methods are developed and applied, thelarge quantities of solid wastes that will need to behandled could pollute the air with fugitive dust andthe water with runoff and Ieachates from storagepiles and waste disposal areas.

Specific findings include:●

●

●

●

●

●

Several approaches can be used to reduce thedeleterious effects associated with the disposal ofspent oil shale. These include reducing surfacewastes by using in situ processing or returningwastes to mined out areas; the chemical, physical,or vegetative stabilization of processed shale; andcombinations of the above.

Research has shown that vegetation can be estab-lished directly on processed oil shales. However,intensive management is required, including theleaching of soluble salts, the addition of nitrogenand phosphorus fertilizers, and supplemental wa-tering during establishment. Revegetating spentshale covered with at least 1 ft of soil is less sus-ceptible to erosion and does not require as muchsupplemental water and fertilizer. Adapted plantspecies are required for either option,

The long-term stability and character of the vege-tation is unknown, but research on small plotssuggests that short-term stability of a few decadesis likely if sufficient topsoil is added.

Reclamation plans will have to be site specificsince environmental conditions vary from site tosite, Proper management will be required in all in-stances, if only to maintain plant communities insurrounding areas. H is even more important inthe reclaimed areas.

Shortages of adapted plants and associated sup-port materials such as mulches probably wouldoccur if a large (ea. 1 million bbl/d) industry is es-tablished. The problem is compounded by the in-creasing demands from other mining operationssuch as coal and other minerals.

The Surface Mining Control and Reclamation Actprovides for the kind of comprehensive planningand decisionmaking needed to manage the landdisturbed by coal development. New reclamationstandards that are applied to oil shale should pro-vide for postmining land uses that are ecologicallyand economically feasible and consistent withpublic goals.

Ch. 8–Environmental Considerations 259

Permitting

During the past 10 years an increasingly complexsystem of permits has been developed to assist theFederal, State, and local governments in protectinghuman health and welfare and the environment. Per-mits are the enforcement tool established by Con-gress and the States to determine whether a pro-spective facility is able to meet specific requirementsunder the law.

Operation of an oil shale facility requires more than100 permits from Federal, State, and local agencies.Included are those for environmental maintenance,for protection of worker health and safety, and for theconstruction and operation of any industrial facility(e.g., building code permits, temporary permits forthe use of trailers, sewage disposal permits). Ofthese 100 permits, about 10 major environmentalones require substantial commitments of time and re-sources.

Findings of the analysis include:

● The time required for preparing and processing apermit application depends on the type of actionbeing reviewed, the review procedures stipulatedunder the law, the criteria used by agencies tojudge the application, and the amount of publicparticipation and controversy that is brought tobear. If Federal land is involved, then an environ-mental impact statement (EIS) will most likely berequired. The EIS process may take at least 9months after the developer applies for permissionto proceed with the project. In the case of the cur-rent Federal lease tracts, additional time wasneeded to prepare detailed development plans(DDP) for approval by the Area Oil Shale Super-

●

●

visor of the U.S. Geological Survey (USGS). Oncethe requirements for an EIS and DDP are satisfied,obtaining all of the needed permits can take morethan 2 years. The project would not necessarily bedelayed by the full length of the permitting sched-ule, because other predevelopment activities suchas engineering design, contracting, and equip-ment procurement could proceed in parallel, if thedeveloper were willing to accept the risk that someof the permits might not be obtainable.

The principal problems encountered to date withthe permitting process are related to the needs ofthe regulatory agencies for technical informationand to differing interpretations of environmentallaw. Future problems may be more critical thanthose encountered thus far. Several relevant regu-lations are still pending that may increase costs orforce changes in the design of process facilities orcontrol technologies. They may also add to thecontrol requirements. Another problem that mightemerge is the ability of regulatory agencies to han-dle the increasing load of permit applications andenforcement duties.

Several attempts are being made to simplify regu-

Air Quality

Iatory procedures. These include the streamliningof permitting procedures within specific agencies;the design and testing of a permit review pro-cedure for major industrial facilities that will coor-dinate the reviews by Federal, State, and localregulators; and the proposed Energy MobilizationBoard to expedite agency decisionmaking and re-duce the impacts of new regulatory requirements.Colorado has recently announced a joint reviewprocess designed to accomplish the first two ofthese ends.

Introduction

The maintenance of air quality is neces-sary for the development of an environmen-tally acceptable oil shale industry. In this sec-tion:

The types of atmospheric contaminantsproduced by oil shale unit operations arecharacterized.

●

●

●

Rates are estimated for the generation ofair contaminants.

The applicable Federal and State airquality regulations and standards aredescribed.

The effects of these regulations andstandards on a developing oil shale in-dustry are analyzed.


● The air pollution control technologiesthat may be applied to untreated emis-sion streams are described and evalu-ated. The net rates at which pollutantswill be emitted in treated streams are es-timated.

● Modeling procedures that may be usedto predict and monitor compliance withair quality regulations are discussed.

● Potential problems that commercial-scale operations may encounter in meet-ing standards are identified.

● Key findings are summarized.● Policy options are discussed.

Pollutant Generation

Oil shale mining and processing will pro-duce atmospheric emissions including thosepollutants for which NAAQS have been es-tablished: sulfur dioxide (SO2), particulate,carbon monoxide (CO), ozone (0 S), lead, andnitrogen oxides (NOX); as well as variousother currently unregulated pollutants, suchas silica, sulfur compounds, metals, carbondioxide (CO2), ammonia (NH3), trace organics,and trace elements. The following discussionexamines the types of pollutants generated byeach unit operation. Where data are avail-able, the rates at which these contaminantswill be produced by different oil shale facil-ities are estimated.

Unit Operations and Pollutants

Mining can be carried out either using un-derground (room and pillar) or surface (openpit) methods. The sequential steps in room-and-pillar mining are drilling, blasting, muck-ing (collection of the blasted shale), primarycrushing, and conveying the reduced shale tothe surface for retorting. Potentially hazard-ous substances (silica, salts, mercury, lead)may be released during blasting. Methanemay be released from underground gas de-posits, and CO, NOX, and hydrocarbons (HC)may be emitted by incomplete combustion ofthe fuel oil used both for blasting and in mo-bile equipment. In addition, particulate canbe emitted as a result of blasting, raw shalehandling and disposal, and activities at the

minesite that produce fugitive dust (particu-late matter discharged to the atmosphere inan unconfined flow stream).

Atmospheric emissions are expected to bemuch larger in open pit than in room-and-pillar mining because of the significantlylarger quantities of solids that must be han-dled on the surface. The mine dust problemwill be further aggravated by road dust fromtransportation of overburden, and wind-blown dust from all operations.

Storage, transport, and crushing of oilshale result in the emission of particulate,CO, NOX, SO2, and HC from fuel in diesel en-gines, and particulate and silica from fugi-tive dust. Dust is the chief pollutant. Theamount generated depends on the grade ofore, the extent to which its size must be re-duced for retorting, the number of transferpoints in the transportation system, and thelevel and effectiveness of control strategiesused.

Retorting technologies generate processheat by the combustion of fossil fuels, whichproduces a number of atmospheric emissions.The amount of SO2 emitted depends on thesulfur content of the fuels used in the plantand the extent to which sulfur-containingproduct gases are treated. The volume andconcentration of hydrogen sulfide (H2S), car-bonyl sulfide (COS), and carbon disulfide(CS2) in the offgas streams from retorts de-pend on the type of retorting technology. COShas been detected in the offgases from Law-rence Livermore Laboratory’s simulated MISretorts and trace quantities of COS and CS2

have been reported in the offgases from theOccidental MIS process under certain oper-ating conditions. It is not known whether theretort offgases from the Paraho, Union “B,”TOSCO II, or Superior processes contain COSor CS2.

The major source of NOX emissions is thecombustion of fuel in boilers, air compres-sors, and diesel equipment. The specific lev-els depend on the combustor design, the ex-tent of onsite fuel use, and the nitrogen con-tent of the fuels used to produce process heator steam. Most of the fuels consumed in oil


shale plants will be produced onsite. Both di-rectly heated aboveground retorts (AGR) andMIS generally produce sufficient low-Btu gasto meet retorting requirements, plus an ex-cess for other onsite uses such as power gen-eration. Indirectly heated aboveground re-torts produce less fuel gas, but it has a higherheating value. In either case, it is possiblethat some shale oil will be burned for processheat. Since both retort fuels (gases and shaleoil) contain nitrogen, they could potentiallyemit more NOX.

HC and CO will be emitted primarily in theexhausts of mobile equipment and in fluegases from boilers and other combustors. HCwill also be emitted in vapors from oil storagetanks, pumps, flanges, seals, and compres-sors, and CO by blasting and rubblizationduring the preparation of MIS retorts. Emis-sion levels from storage tanks should not varywith the type of retorting technology. Theother HC and CO sources have a dependenceon retorting technology that is similar to thatdescribed for NOX. Equipment-related emis-sions are a function of the amount of solidsthat need handling on the surface.

The quantities and the chemical propertiesof the particulate emitted vary with retort-ing technologies. Retorts like TOSCO II thatrequire fine shale feed and produce very fineretorted shale, produce the largest amounts.

The pyrolysis of an organic material like oilshale kerogen produces a certain amount ofpolycyclic organic matter (POM). POM, whichis found in conventional crude oils, has alsobeen found in the carbonaceous retortedshales from TOSCO II, Union “B,” and Para-ho indirect retorts. It is rarely found in re-torted shale that has been subjected to astrong oxidizing environment such as that en-countered in the Paraho direct retort.

Trace elements (particularly the heavymetals) may be released by retorting opera-tions. Compared with average rocks, GreenRiver oil shale contains much higher levels ofselenium and arsenic; moderately higher lev-els of molybdenum, mercury, antimony, andboron; and lower levels of cobalt, nickel,

chrome, zirconium, and manganese.l At typi-cal retorting temperatures (ea. 900° F (480°C)), it is generally accepted that most traceelements are not volatilized. They leave theretort in the spent shale product and in par-ticulate entrained in retort gases and shaleoil. Possible exceptions are antimony, arse-nic, beryllium, boron, copper, fluorine, lead,mercury, nickel, selenium, and zinc, whichcould leave the retort as vapor and be con-densed in the liquid product.2 The heavymetals in raw shale oil are of economic con-cern because they tend to destroy the effec-tiveness of the catalysts used for refining. *Their removal is not expected to present anymajor problems to the refiner. Several propri-etary techniques are available for this pur-pose. It has also been recognized that refiningcatalysts need careful disposal because theymay contain nickel, cobalt, molybdenum,chromium, iron, and zinc, in addition to traceelements captured from the shale oil. Emis-sions can occur during the onsite regenera-tion of these catalysts and during the disposalof spent catalysts in landfill operations.

Upgrading, refining, gas cleaning, andpower generation produce such pollutants asCS2, COS, SO2, H2S, NH3, and HC; with HCbeing the dominant fugitive emission.) Par-ticulate such as fly ash are also produced.

The handling and disposal of raw and re-torted shale could create serious fugitive dustproblems. This dust may contain harmful par-ticulate and possibly POM. The problemsare most severe for technologies like TOSCOII that produce very fine spent shale. Dustproduction should be less of a problem withaboveground retorts like those of Paraho andUnion “B” that produce coarse spent shale,They should be even less significant for MISbecause spent shale will remain undergroundand will not be subjected to wind erosion.

The Amounts of Pollutants Produced

It is difficult at present to estimate thequantities of air contaminants that would be

*Refinery modifications to mitigate this problem are dis-cussed in ch. 5.

262 . An Assessment of Oil Shale Technologies

produced by a commercial-size oil shale facil-ity. The only field measurements that havebeen made to date have been for the small-scale, short-term pilot-plant or semiworksoperations of Colony Development, Paraho,and Occidental Oil Shale.4 These facilities donot simulate normal operating conditions in afull-size facility, and the measurements thathave been made have been mostly of the regu-lated pollutants. Only a few of the nonregu-lated pollutants such as trace elements havebeen measured, and those measurementsthat have been reported show considerablevariation. Pollution production estimatesmust therefore be confined to regulated pol-lutants and must strongly rely on theoreticalcalculations.

The quantities of pollutants produced in anindustrial facility can be estimated by apply-ing pollutant generation factors to the massflows of material through the plant. The pro-cedure used for the calculation, although anapproximation, gives estimates of the prob-lem’s scope. Generation factors obtainedfrom the literature were applied to the massbalances published for Colony’s proposedTOSCO II retorting plant on Parachute Creek,for Rio Blanco’s combination of MIS and AGRprocessing on tract C-a, and for the Occiden-tal MIS operation on tract C-b. All flows werescaled to a uniform production level of 50,000bbl/d of shale oil syncrude. The results aresummarized in tables 34 through 36. Note

that the tables show levels of pollutant gener-ation, not pollutant release.

Of the three designs —Colony, Rio Blanco,and Occidental—Colony produces the largestamount of particulate. This plan uses boththe most underground mining and TOSCO IIAGR, which requires a fine shale feed andproduces a very finely divided shale. Thisretorting method is also responsible for Col-ony’s exceptionally high production of HC. Inthe TOSCO II retorting system, vaporizedshale oil and gases evolved during pyrolysisare stripped of high molecular weight HC in acondenser, and then burned to reheat theheat carrier balls. Because combustion is in-complete, lighter weight HC are entrained inthe offgas stream from the ball heater.

In generating steam for power, the Occi-dental design in which large quantities oflow-Btu gas are burned produces the mostNOX emissions. Rio Blanco, which plans toburn coke from the upgrading units, producesless NOX but more particulate. Colony’s on-site pollutant production in this step will benegligible because it plans to purchase mostof its electricity from offsite powerplants.

The emission of SO2, produced in the NH3

and sulfur recovery processes, is about thesame for all three designs. Although both Col-ony’s and Rio Blanco’s CO emissions are high-er than Occidental’s, the differences are notsignificant.

Table 34.–Pollutants Generated by the Colony Development Projecta (pounds per hour)b

Operation Particulate so, NO, HC c o

Mining . . . . . . . . . . . . . . . . 1,480 0 250 50 440Shale preparation. . . . . . . . . . . 15,940 0 0 0 0Retorting c. . . . . . . . . . . . . . . . . . . . . . . 11,440 150 1,430 480 60Spent shale treatment and disposal . . . . . . . 1,350 0 130 10 0Upgrading. . . . . . . . . . . . . . . . . . . trace 10 20 10 traceAmmonia and sulfur recovery d. . . . . ., 0 32,200 0 0 0Product storage . . . . . . . . . . . . . . . . . . . . . 0 0 0 150 0Steam and power. . . . . . . . . . . . . . . . . . – — — — —

Hydrogen production . . . . . . . . . . . . . . . . . 10 30 80 trace 10

Total ... . . . . . . . . . . . . ., . . . . . 30,220 32,390 1,910 700 510

c3Tafj~ shows the ItIVtIt Of pOllUlafll generation, not pollufanf releaseb Ro o m .a nd .p illar mlnlng, TOSCO II retorting, scaled 1050,000 bbl/d Of shale oll syncrude productioncFlgures do not include components of the product gas and VaPOr streamalso, equivalent of H*S m retort 9as stream

SOURCE T C Borer and J W Hand, /derr//hcal/on and Proposed CorJlro/ 01 A/r Po//ufartfs from O/l Sha/e Operations, prepared by the Rocky MountainDiwslon, The Pace Company Consultants and Engineers, Inc for OTA, October 1979


Table 35.–Pollutants Generated by the Rio Blanco Project on Tract C-aa (pounds per hour)b

Operation Particulates so, NO. HC co

Mining. ,, .,,,.. ,. 1,050Shale preparation. . . . ., . . . . 7,200Retorting ., 8,900Spent shale t reatment and d isposal 650Upgrading. ., ., 7Ammonia and su l fur recovery d ., ., ., 0Product storage ., ., 0Steam and power. ~ ~ ~ ~ 210Hydrogen production –

T o t a l 18,017

40

5200

19,2000

250—

340200320

0700

1,220—

800

1000

130

10513

—

4300000000—

19,506 2,087 311 430

aTab[e shows lhe level of poilulanl generation not pollutanf releasebundergroun~ mlnlng modlfled [n SIfU and TOSCO II aboveground retorlng scaled tO 50000 bblld of shale oll syncrudecFlgures do not !nclude components of The product 9as and vaPor streamalso, ~qulvalen[ Of H,S In retofl 9as s(ream

SOURCE T C Borer and J W Hand /deohf/cat/on and Proposed Corrtro/ of A/r Po//ufarrts lrorn 0// Shale OperaOorrs prepared by the Rocky MountainOwslon The Pace Company Consultants and Eng(neers Inc for OTA Oclober 1979

Table 36.–Pollutants Generated by the Occidental Operation on Tract C-ba (pounds per hour)b

Operation Particulate so, NO, HC c o

M i n i n g 4,540 0 300 120 180Raw shale disposal ~ 450 0 100 10 0Retorting c ~ 0 0 0 0 0U p g r a d i n g . . 10 10 80 trace 10A m m o n i a a n d s u l f u r r e c o v e r yd . , 0 24,000 0 0 0P r o d u c t s t o r a g e 0 0 0 80 0Steam and power. . 20 trace 2,800 0 0H y d r o g e n p r o d u c t i o n 80 20 220 20 20

T o t a l 5,100 24,030 3,500 230 210

aTa~ie shows [he level of ~oliufan[ generation not pollutant releasebunderground mlnlng modlfted in sdu retorting scaled to 50000 bbl d Of shale 011 syncwdecFlgures do not Include components of tne product gas and vaPOr streamdsol equivalent o! HIS m reforl 9as stream

SOURCE T C Borer and J W Hand Idenhkaflon and Proposed Cofltrol of +Vr Po//ufartk from 0// .S/ra/e Opera(/orm prepared by the Rocky MountainOw!s!on The Pace Company Consultants and Eng[neers Inc for OTA Oclober 1979

It should again be noted that the tablesshow the amounts of pollutants generated,not the amounts released. Pollutant emissionsare regulated by laws and standards, whichare discussed in the next section. Compliancewith these laws and standards requires pollu-tion control technologies, which are dis-cussed later in the

Air Qualityand

Introduction

chapter.

Laws, Standards,Regulations

The existing and proposed regulations andstandards governing air pollution from the oilshale industry are discussed here becausethey will affect the design and operatingcharacteristics of oil shale facilities. They

may also act to constrain the ultimate size ofthe oil shale industry.

Air quality regulation is called for by theFederal Clean Air Act of 1970, as amended in1977, hereafter referred to as the “Act.” Reg-ulations and standards arising from this Actare implemented at the Federal level by EPAand at State levels in conjunction with addi-tional regulations and standards imposed bythe individual States. The following discus-sion first highlights major provisions of theAct, and then analyzes those that are particu-larly significant for oil shale development.

Highlights of the Amended Clean Air Act

The Clean Air Act, as amended, estab-lishes a national program to regulate air

.


pollution in order to maintain or improve airquality. The Act is universally applicable, butits provisions are most strongly directed tothose areas having the cleanest air (nondeg-radation areas) and those where air pollutionmay be hazardous to public health (nonattain-ment areas). The major elements of the pro-gram established by the Act are:

●

●

●

●

the establishment of NAAQS for criteriaair pollutants,the submission by each State of a Stateimplementation plan (SIP) to achieve andmaintain Federal air quality standards,the preconstruction review of major newstationary sources, andPSD.

National ambient air quality standards.—Regulation under the Act focuses on six cri-teria pollutants: particulate, SO2, CO, NOX,03,, and lead. Two types of ambient air qualitystandards are designated: primary stand-ards, which protect human health; and sec-ondary standards, which safeguard aspectsof public welfare, including plant and animallife, visibility, and buildings. The Act setsforth an exact timetable by which primarystandards are to be met. Secondary stand-ards are to be met on a more flexible sched-ule.

To achieve air quality goals, areas with aircleaner than NAAQS were divided intoClasses I, II, and III. Certain Federal areasthat existed when the Act was passed (e.g.,national parks, wilderness areas) were imme-diately designated as Class I areas where airquality was to remain virtually unchanged.All others were designated as Class II—areasin which some additional air pollution andmoderate industrial growth were allowed. In-dividual States or Indian governing bodiescan redesignate some Class II areas to ClassIII—areas in which major industrial develop-ment is foreseen and contamination of the airup to one-half the level of the secondarystandards would be permitted. The States orIndians can also redesignate Class II areas asClass 1. Either type of redesignation is subjectto hearings and consultations with the man-

agers of affected Federal lands (and States inthe case of Indian action).

The classification of an area with respectto the ambient air quality has important con-sequences. The Act divided the Nation into247 air quality control regions (AQCRs) sothat pollution control programs could be lo-cally managed. Compliance with an NAAQSis generally determined on an AQCR basis,but EPA allows smaller area designations forsome pollutants, if that is more suitable forcontrolling pollution.

These AQCR designations are highly signif-icant. Regions that are found by EPA to be innonattainment status—areas where air pol-lution presents a danger to public health—are subject to a particular set of restrictionsunder the Act. On the other hand, nondegra-dation regions—where air is cleaner than thestandards—are subject to a different set ofregulations, which are intended for “preven-tion of significant deterioration. ” Regardlessof an area’s classification, almost every newmajor source of pollution is required toundergo a preconstruction review.

State implementation plan.—Each Statemust submit an implementation plan for com-plying with primary and secondary stand-ards. A State can decide how much to reduceexisting pollution to allow for new industryand development. State plans must also in-clude an enforceable permit program for reg-ulating construction or operation of any newmajor stationary source in nonattainmentareas, or significant modification to an exist-ing facility. New processing plants and powerstations must also satisfy emission standardsset forth in the SIP.

Preconstruction review of major new sta-tionary sources. —Under the SIP, each newconstruction project is subjected to five typesof preconstruction review. The objective ofthe review process is to determine:

● compliance with NAAQS and State AirQuality Standards (AQS);

● compliance with any applicable NSPS; suitability for a nonattainment area;


●

●

The

suitability for a nondegradation area.(PSD regulations, including the use ofBACT and PSD increments* will apply);andvisibility.

major elements of these preconstructionreview procedures are:

● Review for compliance with NAAQS.The applicant must submit plans andspecifications for review that show:methods of operation, quantity andsource of material processed, use anddistribution of processed material, andpoints of emission and types and quanti-ties of contaminants emitted; a descrip-tion of the pollution control devices to beused; an evaluation of effects on ambientair quality and an indication of compli-ance with PSD restrictions; and plansfor emission reduction during a pollutionalert. A permit will not be given if it isshown that the source will interfere withthe maintenance of any ambient airquality standard or will violate any Stateair quality regulation.

Review for compliance with NSPS. TheAct directed EPA to set national stand-ards for fossil fuel powerplants, refin-eries, and certain other large industrialfacilities. If NSPS have been establishedfor the new source, it must be shownthat the facility will not interfere withthe attainment or maintenance of anystandard and that BACT will be used forreducing pollution.

● Review in nonattainment areas. In non-attainment areas, a new facility may bebuilt only if: by the time operations com-mence total emissions from it, and othernew and existing sources, will be lessthan the maximum allowed under SIPS;the source complies with the more strin-gent of either emission limitations re-quired by the State or achieved in prac-tice by such a source; and the owner oroperator demonstrates that all other ma-

*In part BAC’I’ is required 10 assure that no single facilitywili consume the entire PSf3 increment.

●

jor stationary sources owned or oper-ated by him in the State comply withemission limitations.

Review in nondegradation areas. Thistype of review, which concerns PSD, isdiscussed below.

The prevention of significant deteriora-tion.—All SIPS must specify emission limita-tions and other standards to prevent signifi-cant air quality deterioration in each regionthat cannot be classified for particulate orSO2, or has air quality better than primary orsecondary NAAQS for other pollutants, orcannot be classified with regard to primarystandards because of insufficient informa-tion.

Under these PSD standards, maximum al-lowable increases in concentration of SO2

and particulate are specified for each areaclass. For the other criteria pollutants, max-imum allowable concentrations for a speci-fied period of exposure must not exceed therespective primary or secondary NAAQS,whichever is stricter.

A State can redesignate a Class II or IIIarea with respect to PSD only if it follows cer-tain procedures. These include an assess-ment of the impacts of the redesignation, pub-lic notice and hearings of such a redesigna-tion, and approval by EPA.

If a facility’s construction began after Jan-uary 1, 1975, a special preconstruction re-view must be undertaken if it is located in anondegradation area. To obtain a permit forsuch a facility, an applicant must demon-strate that it will not cause air pollution in ex-cess of NAAQS or PSD standards more thanonce per year in any AQCR. BACT must beused for all pollutants regulated by the Act,and the effects of the emissions from the fa-cility on the ambient air quality in the areasof interest must be predicted. The air qualityimpacts that could be caused by any growthassociated with the facility must also be ana-lyzed.

63-898 0 - 80 - 18


Implications of the Clean Air Act forOil Shale Development

The following provisions of the Act haveparticular significance for oil shale develop-ment:

● compliance with NAAQS and State AQS;● maintenance of air quality, especially

visibility, in adjacent Class I areas (e.g.,national parks);

● compliance with PSD increments;● compliance with NSPS; and● the application of BACT.

National Ambient Air Quality Stand-ards.—Ambient air quality standards pro-mulgated by individual States cannot be lessstringent than the national standards. Thus,the States set the controlling standards ifthere is an approved SIP. Utah’s standardsare identical to the national standards, whileColorado and Wyoming have set more strin-gent standards for a number of the criteriapollutants. Table 37 shows both the nationalstandards (the same for Utah), and Colo-

rado’s and Wyoming’s standards. In additionto the standards shown for Wyoming, theState has also promulgated regulations tolimit ambient concentrations of H2S, hydro-gen fluoride, and other pollutants. The stand-ards are more relevant to large coal-firedpowerplants than they are to oil shale proc-essing.

Since the national standards are primarilydirected to urban areas, they should not seri-ously restrict oil shale development in thenear future. The annual-average pollutionlevels allowed by ambient standards aremuch higher than the values normally meas-ured in the oil shale development area. How-ever, the short-term standards for particu-late and HC are occasionally exceeded bynatural emissions such as windblown dustand HC aerosols produced by revegetation.Such naturally caused infractions of NAAQScould have restricted regional development.They actually did affect oil shale developmentschedules on the four lease tractsColorado and Utah. According to

located inthe provi-

table 37.–The Federal and State Ambient Air Quality Standards and Prevention of Significant DeteriorationStandards That Influence Oil Shale Development (concentrations in micrograms per cubic meter)

Prevention of significantAmbient air quality standards deterioration standards

Federal (primary) Federal (secondary) FederalPollutant human health public welfare Wyominga Colorado a Utah a (Class 1) (Class II)

so,Annual arithmetic mean, . .2 4 - h o u r m a x i m u m . . .3-hour maximum . . . . . . .

ParticulatesAnnual geometric mean. . . .24-hour maximum . . .

/VOX (as NO,)Annual arithmetic mean. . . . .

Oxidants (as O,)l-hour ., ., ., ... . .

co8 - h o u r m a x i m u ml-hour maximum . . . . .

LeadQ u a r t e r l y .

Nonmethane hydrocarbons3-hour maximum (6-9 am). .

80365

None

NoneNone

1,300

60260

1,300

80365700

80365

None

25

25

2091

512

75260

60150

60150

45150

75260

510

1937

100 100 100 100 100 None None

240 240 160 160 240 None None

10,00040,000

10,00040,000

10,00040,000

10,00040,000

10,00040,000

NoneNone

NoneNone

1,5 1.5 1,5 1.5 1 5 None None

160 b 160b 160b 160 b 160 b None None

astate amblen( alr ~uallly qandards are ,de”tl~al to the Federal prlrnary standards unless prlfllecl lrl llallcs The s!ncter standard IS the Conlro[llrlg standardbNot a standard, a guide 10 show achievement of o] standardcAllowable Incremental change m ambient Coflcefltratlon

SOURCE Olf{ce of Technology Assessment

Ch. 8–Environmental Considerations . 267

sions of the Act, the tracts and their environswere nonattainment areas. As such, theywere not subject to any additional develop-ment. This potential barrier was cited bysome of the tract lessees in their requests foractivity suspensions in the fall of 1976.

In December 1976, EPA ruled that new de-velopment could proceed in a nonattainmentarea if the developer would offset new emis-sions by reducing the same emissions from anexisting source in the same area. Althoughpossibly applicable to urban or industrializedareas, such a policy was not relevant to theoil shale regions because there are no sub-stantial existing industries against which tooffset oil shale emissions. EPA made a subse-quent ruling in July of 1977 that air qualityproblems arising from natural sources wouldnot preclude oil shale development, providingthat facilities complied with emission andPSD standards. The history of this ruling andits effects are discussed in detail in theanalysis of the Prototype Oil Shale LeasingProgram. (See vol. II.)

A second consideration is the visibility pro-tection afforded to Federal mandatory Class Iareas under the Act. Regulations are to bepromulgated by EPA by November 1980, andby the States by August 1981. These regula-tions may affect the siting of future oil shalefacilities.

Compliance with standards for PSD.—PSDstandards exist for Class I, II, and III areas.The oil shale area is a Class II region, whichmeans that some additional pollution will beallowed, but pollution up to the level of ambi-ent air quality standards will not be accept-able. EPA’s PSD standards define the max-imum allowable increases in S02 and particu-late concentrations. These standards areshown in table 38.

In summary, an oil shale facility will haveto meet the PSD requirements for Class IIareas, and moreover, it will not be allowed todegrade air quality in nearby Class I areasbeyond the limits specified under the PSDprovisions of the Act. Because most pollut-ants emitted by oil shale facilities can travellong distances, the stringent PSD increments

Table 38.–National Standards for Prevention ofSignificant Deterioration of Ambient Air Quality

(concentrations in micrograms per cubic meter)

Maximum allowable increase

Pollutant Averaging time Class I Class II Class Ill

P a r t i c u l a t e s Annual 5 19 3724 hour 10 37 75

so, ., Annual 2 20 4024 hour 5 91 182

3 hour 25 512 700

aEpA IS presently developing Incremental standards tor HC CO O, NOX and pb

SOURCE Environmental Profechon Agency Work Group Po//ufIorI Cm(m) Guidance (or 01/ Sha/eDe(e/oprr?en/ A p p e n d i c e s 10 /he Rewsed Llraf/ EPA Clnclnna!l Ohto July 1979 p0-17

for Class I areas could affect the siting of oilshale facilities. Figure 59 shows the Class Iareas located near oil shale country in Col-orado, Utah, and Wyoming. The two Coloradoareas nearest the oil shale deposits are theexisting Flat Tops Wilderness and the pro-posed Dinosaur National Monument.

Preconstruction review for oil shale facil-ities.—Under the Clean Air Act, each new oilshale plant must be evaluated during a pre-construction review to determine its ability tocomply with NAAQS and PSD regulations.Projected emission levels will be regulated byEPA’s NSPS, State emission standards, andthe mandated use of BACT.

At present, there are no Federal emissionstandards that deal specifically with oil shaleoperations. However, NSPS have been devel-oped for fossil-fuel-fired steam generators,petroleum refineries, and Refinery ClausSulfur Recovery Plants. Table 39 lists the ex-isting and proposed NSPS for these facilitiesas a guideline to what might be consideredfor oil shale plants. In addition, Colorado hasdeveloped emissions standards for shale oilproduction and refining that limit the sum ofall S02 emissions from a given facility to 0.3lb/bbl of oil produced or processed. Plantssmaller than 1,000 bbl/d are exempt. AnotherColorado regulation limits H2S ambient con-centrations from all shale oil plants to 142micrograms per cubic meter (142 pg/m3 or 0.1p/m). Utah and Wyoming do not have applica-ble emission limits. BACT standards havebeen developed by EPA for those oil shale fa-cilities that have applied for PSD permits, as


Figure 59.— Designated Class I Areas in Oil Shale Region

W Y O M I N G

‘ - - — - -- --DAGGETT I

.MOFFAT

● GRI==STONE

VER;AL

—r- ~-”

I I. I

UINTAH1

<b

. . — . — . — . — . — .—. —

BONANZA I g ● RANGELY MEEKER —,

LDINOSAURI.

●

-~k

. .

●

●

_ 1<T

- 1● ●

xl% R I O BLANCO A “ — . —.-$’Y L

u -r

L

3: ● —* —* JRIO BLANCO .. —.—.3

“ L . — . ~

J GARFIELD GLENkVOOD%J1

“ — . — . — . — . SPRINGS‘.-. I

‘RAND::YA* i

r

+ . — . — . — . — . L>.—.

G R A N D

sLEGEND:

❑ FOREST AREAS

i

IM E S A ‘“;.vDELT~-’-r- &

I.L . —.—. — .–.5? (

I I.

I. — . — . — . J

I MONTROSE5

i GUNNISON

AREA DESIGNATIONS

Federal Mandatory Class I Areas: 1, 2, 3,4, 6Colorado Class I Areas: 5, 6,8

Draft Proposed (NPS) Class I Areas: 6, 8

CLASS I AREAS

1. Flat Tops Wilderness 5. Black Canyon of the2. Mount Zirkel Wilderness Gunnison Monument3. Maroon Bells—Snowmass Wilderness 6. Colorado National Monument4. West Elk Wilderness 7. Arches National Park

8. Dinosaur National Monument

SOURCE: Environmental Protect ion Agency Work Group, ~0//ut/orI c20~fr0/ Gwdarme /of 0// Shale ~eveloweflf Awerrdmes to (he Rev/seal Draft, U S. EnvironmentalProtect ion Agency, Clnclnnatl, Ohio, July 1979, p. D.41


Table 39.–National New Source Performance Standards for Several Types of Facilities’

Operation Pollutant Removal or emission standardb Status

Fossil fuel fired steam generators Particulates 0.1 lb/m Btu ExistingS02, NOx 0.8 lb/m Btu for gaseous fuels; 0.3 lb/m Btu for liquid fuels

Petroleum refineries H2S 0.1 gr/scf (dry) ExistingHC Floating roof tanks or vapor recovery systems if true vapor

pressure IS between 1,5 and 11,1 lbt/in2a and reportingsystem only if pressure is less than 1.5 lbf/in2a

Refinery Claus sulfur recovery plants H2S 0,1 gr/scf (dry) ExistingSulfur 250 p/m SO, for oxidation systems, 300 p/m total sulfur and

10 p/m H2S for reduction systems

Gas turbines NOx 75 p/mat 15Y0 oxygen Proposed for units over 10so, 150 p/m m/ Btu per hour

Gasification plants Sulfur 99,0% removal and 250 p/m total sulfur GuidelineHC 100 p/m

Field gas processing units H2S 160 p/m Proposedso, 250 p/m for oxidation systemsSulfur 300 p/m for reduction systems

apre~ented ~~ ~ g“lde to what mlghl be considered for oll shale facl[lllesbib, ,nza = ~ound~ ~er square Inch absolute p/m = ~er mltlron Scf = standard cubic feel

cStandards tor fossil fuel fired steam generators being fevlsed

SOURCE Environmental protection Agency Work Group Pol)ul/on Con/ro/ Gu@arme for OIJ Sha)e Deve/opmenl ,.lppendmes fo fhe RewseO Dra(f. EPA Clnclnnatl Oh!o July 1979 p D 34

shown in table 40. These standards specifylevels of removal efficiency for specificpollutants, and in some cases also define themaximum concentration that will be allowedin the emitted stream.

In summary, oil shale facilities will have toundergo preconstruction review. BACT willbe required for all pollutants regulated by theAct, and plants will have to comply with am-bient air quality and PSD standards for ClassII areas. Facility siting might be affected byPSD standards in adjacent Class I areas. Theeffects of visibility standards, which have yet

Table 40.–EPA Standards for Best Available Air PollutionControl Technologies for Oil Shale Facilitiesab

.Pollutant Removal requirement

S u l f u r 99.0% total recovery

Particulates. 99.O% from combustiongas streams

99 80/o from materials-handling gas streams

Fugitive dust controlNOx Complete combustionc o Complete combustionHC Complete combustion

Maximum emissions

15 p/m H2S (reduction systems)250 p/m SO2 (oxidation systems)No standard

0.5lb/mBtuNo standardNo standard

ap m = pafls per mlllhon~These s[andards hake been used In EPA s PSO Cleclslon process In the Pas!

S O U R C E Enilronmenlal Proteclton Agency Work Group Po//olIon Cor?ko/ G~,dancr for 0/1 Sha/eLleveopmenf 4ppeoUmes to /he Rewsed Llraf! E P A Clnclnnah O h i o J u l y 1 9 7 9 pD 35

to be promulgated, cannot be determined atthis time.

Air Pollution Control Technologies

In order to comply with the air quality lawsand regulations, oil shale facilities will haveto control their pollutant emissions. Variousaspects of pollutant control are discussed inthis section.

●

●

●

The control technologies that can beused to reduce emissions of particulate,H2S, sulfur compounds, NOX, HC, and COare described, and their potential appli-cations to oil shale mining and process-ing are discussed.The technological readiness of thesetechniques are evaluated.The costs of air pollution control in com-mercial-scale oil shale plants are esti-mated.

Technologies and Applications

DUST CONTROL

Water sprays. —Water sprays can be usedto control fugitive dust. If adjusted properly,no surface runoff will result. Water sprays

270 An Assessment of Oil Shale Technologies

are about 80-percent efficient for particleslarger than about 5 microns, * but less so forsmaller ones. Adding a wetting agent reducesthe surface tension and improves the wetting,spreading, and penetrating characteristics ofthe water, increasing efficiency to 90 to 98percent. Chemical binders, such as latex orbitumastics, can also be added. They aid inparticle agglomeration and also increase theefficiency of removal. Water sprays, with orwithout chemical additives, are potentiallyapplicable to raw and spent shale storageand disposal, to crushing and screening, tomining and blasting, and to surface trans-portation. They could also control traffic dustfrom temporary roads, Larger, more heavilytraveled roads would probably need to bepaved.

Cyclones.—Cyclone separators removedust by means of centrifugal force. Single cy-clones remove about 90 percent of the largerparticles, but less than 50 percent of thosesmaller than about 10 microns. Their removalefficiencies could be increased by using sec-ond-stage cleaning in scrubbers, filters, orprecipitators. Cyclones will be used largely toclean retort gases, and possibly for primarydust control in crushers and enclosed convey-ors.

Scrubbers.— Wet scrubbers use water toremove dust entrained in gas streams. Manydifferent types of devices are available, in-cluding spray chambers, wet cyclones, me-chanical scrubbers, orifice scrubbers, ven-turi scrubbers, and packed towers. High-en-ergy venturi scrubbers are probably the onlytype that have sufficiently high removal effi-ciencies to satisfy emissions standards. Effi-ciencies between 93.6 and 99.8 percent havebeen achieved for particles smaller than 5microns, but these efficiencies entail highpressure losses and constant gas flow rates.Scrubbers require considerably more energythan baghouse filters or electrostatic precipi-tators. Scrubbers for particulate removal will

*A micron is one-millionth of a meter. Removal efficienciesfor different particle sizes are important because effects onrespiration and visibility vary with the particle size.

probably be used for gas streams from re-torts and solid heaters.

Baghouse filters. —Fabric filters are gen-erally used where higher removal efficiencyis required for particles smaller than about10 microns. A large number of bag-shaped fil-ters would be needed to clean large gas flows.In general, all of the filters would be enclosedin the same structure, called a “baghouse,”and would share input and output gas mani-folds. As a gas stream passes through thebaghouse, dust is removed by one or more ofthe following physical phenomena: inter-section, impingement, diffusion, gravitationalsettling, or electrostatic attraction. The ini-tial filtration creates a layer of dust on thebag fabric. This layer is primarily responsiblefor this method’s high removal efficiency; thefilter cloth serves mainly as a support struc-ture. The operation is very similar to that of ahousehold vacuum cleaner.

The efficiency of a baghouse filter dependson the particle size distribution, the particledensity and chemistry, and moisture. Undermost conditions a properly designed and op-erated baghouse will achieve a removal effi-ciency of at least 99 percent for particles assmall as 1 micron. Baghouse filters are likelyto be used for dust removal from crushers,screens, transfer points, and storage bins.

Electrostatic precipitators.—In electro-static precipitators, an electrical charge is in-duced on the surface of a dust particle andthe particle is captured on a screen havingelements with the opposite charge. Dry pre-cipitators have been used for many years;wet precipitators and charged droplet scrub-bers have been developed more recently. Alltypes are in common use in the electricalpower generating industry, in cement andsteel plants, and in many other industries.Precipitators have removal efficiencies of upto 99.9 percent, require little maintenance,can handle large flow rates, and have low en-ergy requirements. They might be used in sev-eral oil shale operations, including mine ven-tilation and the second-stage cleaning of dust-


laden streams from crushers and conveyors.A wet precipitator was used at the Parahodemonstration plant for the combined remov-al of shale oil vapors and particulate fromthe retort offgas. One is being used in thePetrosix plant in Brazil for the same purpose.

HYDROGEN SULFIDE CONTROLThe systems for removing H2S that are like-

ly to be used for oil shale operations can gen-erally remove at least 98 percent of this pol-lutant. They will probably be applied to gasstreams from retorting and upgrading opera-tions.

Stretford Process. —In this process, thegas stream is scrubbed in an absorptiontower with a solution containing sodium car-bonate, sodium metavanadate, and anthra-quinone disulfonic acid (ADA). Reduction ofthe metavanadate with H2S in solution causessulfur to precipitate. The metavanadate is re-generated by oxidation with the ADA, and thereduced ADA is then regenerated by beingoxidized in an air stream. The process wasdeveloped for coal- gas treatment, but it hasbeen used for many other purposes in a num-ber of plants, especially oil refineries, in theUnited States and Europe.

Any COS and CS2 that may also be in thegas stream would not be removed in this proc-ess and their presence would interfere withH2S removal. Therefore, before H2S removalthe gas stream would need to be pretreated toremove these compounds.

Selexol and other physical absorptionprocesses. —In these processes, H2S is dis-solved in a solvent and subsequently recov-ered. The solvent is recycled. The earliestprocess, a simple water wash, was inefficientbecause H2S is not very soluble in water.Modern processes use solvents in which it ismore readily dissolved.

Absorption processes are usually used fortreating high-pressure gases and for reducingthe concentrations of H2S and other sulfurcompounds to extremely low levels. Theseprocesses involve the selective absorption ofH2S from gases containing CO2. This producesan H2S-rich stream that can be processed in a

Claus plant (see below). Absorption processescan also remove sulfur compounds, such asCOS, CS2, mercaptans, and thiophenes, whichcannot be processed in a Stretford unit. Be-cause of its low cost and simplicity, the Selex-01 process is a good candidate for use in oilshale plants.

Claus process. —The Claus process, whichis perhaps the oldest and best known methodfor recovering sulfur from streams that con-tain both H2S and SO2, has several variations.With a feed stream containing only H2S, therequired S02 is obtained by oxidizing part ofthe H2S to S02 by burning it in air, and thenmixing the combustion products with the feedstream. The S02 and H2S are then reactedwith each other in a series of converters toproduce elemental sulfur, which is removedby condensation. The feed stream must havea relatively high concentration of sulfur com-pounds in order to achieve a high conversionefficiency with reasonable equipment size.

This process has problems with both main-tenance and downtime, thus backup units areoften needed. Problems arise from sulfur con-densation in the supply and product pipe-lines. The procedures for startup and shut-down are time-consuming, and moisture andCO2 in the feed gas are particularly trouble-some.

The tail or treated gas from a Claus plantstill contains fairly sizable concentrations ofH 2S and S02. It can be recirculated, mixedwith a large volume of stack gas and re-leased, or treated in other systems. In oilshale plants, it is likely that the Claus planteffluent would require further treatment be-fore being released. Processes developed spe-cifically for this purpose include the SCOT,Beavon, and IFP techniques described below,

SCOT (Shell Claus Offgas Treating) proc-ess. In this process, the offgas is heatedwith a reducing gas such as hydrogen,and the mixture is passed through a co-bait-molybdate catalyst bed where allthe sulfur compounds are reduced toH2S. The gas is then sent through an ab-sorber where the H2S is dissolved and


concentrated. The concentrated H2S isliberated from the absorbing medium byheating and is returned to the Clausplant.

The SCOT process is adversely af-fected by high concentrations of CO2.Since gaseous emissions from oil shaleprocessing are expected to be rich inCO2, higher rates of recycling, more com-plete fuel combustion, and perhapssteam injection to dissolve the CO2 maybe necessary.

● Beavon process. In this process, the tailgas from a Claus plant is mixed with hotcombustion gases and passed through acatalyst where all the sulfur compoundsare converted to H2S. The H2S-rich gas iscooled by a slightly alkaline buffer solu-tion and then treated in a Stretford unit.The Beavon process is also adversely af-fected by high CO2 concentrations in thefeed stream. Its use in oil shale plantswould require adaptations similar tothose needed for the SCOT process.

● IFP [Institute Francais du Petrok] proc-ess. The basic reaction in this process isthe same as in the Claus process exceptthat it takes place in a liquid rather thana gaseous phase. The liquid is a polyalky-lene glycol with a 5-percent concentra-tion of a glycol ester catalyst. Both H2Sand S02 are very soluble in this liquid,and efficient conversion to sulfur re-sults. The most important operating vari-able is the H2S to S02 ratio which mustbe at least 2. The process is flexible andcan accommodate wide changes in con-taminant concentrations while maintain-ing constant conversion rates. Also, be-cause the gases can be treated at highertemperatures than in other processes,heat losses are reduced.

SULFUR DIOXIDE CONTROLThe amount of SO2 that will have to be re-

moved will depend on the prior degree of gastreatment and the type of fuel used in proc-essing. Most oil shale plants will probably usedesulfurized fuel for heating, processing, andpower generation. Where large amounts ofS O2 are emitted, such as in the tail gas of a

Claus plant, its control may be required. Thefollowing technologies could be used for thispurpose.

●

●

●

Wellman-Lord process. This is a versa-tile process, widely used by many differ-ent industries, and should be adaptableto the oil shale industry. Colony plans touse it for a commercial-scale above--ground retorting plant.

This process relies on the reaction ofSO2 with sodium sulfate to produce sodi-um bisulfite. The bisulfite solution isnext heated in an evaporator. This re-verses the reaction, liberating a concen-trated stream of SO2. The SO2 can thenbe converted to either elemental sulfuror sulfuric acid. The regenerated sodiumsulfate produced when the reaction isreversed by heating, is dissolved and re-cycled. The current version of this proc-ess is considered to be a second-genera-tion technique for SO2 removal. Previousproblems with sludge production andscaling have been reduced.Double alkali process. Double alkalitechnology resembles conventional wetstack-gas scrubbing methods but avoidsmost of their problems by using two alka-line solutions, sodium hydroxide and so-dium sulfite, to convert SO2 to sodium bi-sulfite. The spent scrubber solution is re-generated by using lime or limestone toconvert the bisulfite to sodium hydroxideand a precipitate that is a mixture of cal-cium sulfite and calcium sulfate. Theprecipitate sludge, which contains thecaptured S0 2, can be disposed of inponds.

Performance of the system is well-established, and over 99-percent S02 re-moval has been achieved with S02 con-centrations in the treated flue gas of lessthan 10 p/m. Potential environmentalproblems are associated with waste dis-posal because the solid residue containssoluble alkaline sodium salts that couldpollute surface and ground water in thevicinity of disposal sites.Nahcolite ore process. Nahcolite is amineral that contains 70 to 90 percent


sodium bicarbonate. It is found in the oilshale deposits in the central Piceancebasin of Colorado. When crushed andplaced in contact with hot flue gases in abaghouse, nahcolite converts SO2 to drysodium sulfate. Typically, 20 percent ofthe required nahcolite would be used toprecoat the filter bags in the baghouse,and the remainder would be sprayed di-rectly into the flue gas stream. The sodi-um sulfate produced and any unreactednahcolite would be sent to disposal,Pilot-plant experiments have shown thatS02 removal efficiencies are between 50to 80 percent depending on flow ratesthrough the baghouse and the ratio ofnahcolite to SO2.

NITROGEN OXIDES CONTROLNitrogen oxides are produced in the com-

bustion of fuels, NOX control can be ap-proached in two ways: by adjusting combus-tion conditions to minimize NOX production,or by cleaning the NOX that is produced fromthe stack gases, At present oil shale devel-opers plan to design combustor conditions forlow NOX production. Gas cleaning systemscould be added in the future, if the needarises for further NOX control, However, withproper design and maintenance of combus-tion equipment, external control systems willprobably not be needed in order to complywith existing regulations.

HYDROCARBON AND CARBON MONOXIDE CONTROLS

The emission of HC and CO will be causedby the incomplete combustion of the fuel forthe boilers, furnaces, heaters, and dieselequipment used in oil shale plants, The con-trol of external combustion sources such asboilers is primarily through proper design,operation, and maintenance. Well-designedunits emit negligible amounts of CO and onlysmall amounts of HC. Instrumentation isneeded to assure proper operating condi-tions, and comprehensive maintenance pro-grams will be needed to keep emission levelsfrom rising due to fouling and soot buildup.The proper maintenance of diesel and otherinternal combustion engines can similarlykeep HC and CO emissions very low. Treating

the flue gas from combustion sources for par-ticulate or SO2 will also reduce HC and COemissions. With proper maintenance, it willprobably be unnecessary to further reduceemissions from these sources.

Other emissions of HC will be caused bypreheating raw shale prior to retorting andby storing crude shale oil and refined prod-ucts. Incineration is probably the only realis-tic way to control them. Storage tank emis-sions can be minimized by using floating-rooftanks, which can accommodate higher vaporpressures than cone-roof tanks without theneed for venting.

OTHER EMISSIONS CONTROLS

Emission control by direct flame incinera-tion systems (also called thermal combustion)is widely used to reduce the amounts of HCvapors, aerosols, and particulate in gasstreams. These systems are also used to re-move odors and reduce the opacity of plumesfrom ovens, dryers, stills, cookers, and refuseburners. The operation consists of ductingthe process exhaust gases to a combustionchamber where direct-fired burners burn thegases to their respective oxides. A well-designed plant flare system is a good exampleof direct incineration control.

Catalytic incineration is also used for thesame purpose. The chief difference is that thecombustion chamber is filled with a catalyst.On contact with the catalyst, certain com-ponents of the process gases are oxidized.The use of a catalyst allows more completecombustion at lower temperatures, thus re-ducing fuel consumption and allowing the useof less expensive furnace construction. How-ever, catalysts are generally selective andmay not destroy as many contaminants as di-rect flame incineration. In addition, becauseof the potential for catalyst fouling and poi-soning, gas streams may need to be cleaned ofsmoke, particulate, heavy metals, and othercatalyst poisons,

Condensation is usually combined withother air pollution control systems to reducethe total pollutant load on more expensivecontrol equipment. When used alone, conden-


sation often requires costly refrigeration toachieve the low temperatures needed for ade-quate control.

Several methods can be used for coolingthe gas streams. In surface condensers, thecoolant does not contact the vapor or conden-sate; condensation occurs on a wall separat-ing the coolant and the vapor. Most surfacecondensers are common shell-and-tube heatexchangers. The coolant normally flowsthrough the tubes; the vapor condenses on thecool outside tube surface as a film and isdrained away to storage or disposal.

Contact condensers usually cool the vaporby spraying a liquid, at ambient temperatureor slightly cooler, directly into the gas stream.They also act as scrubbers in removing va-pors that do not normally condense. The useof quench water as the cooling medium re-sults in a waste stream that must be con-tained and treated before discharge.

The equipment used for contact condensa-tion includes simple spray towers, high-ve-locity jets, and barometric condensers. Con-tact condensers are, in general, less expen-sive, more flexible, and more efficient in re-moving organic vapors than surface condens-ers. On the other hand, surface condensersrecover marketable condensate and presentno waste disposal problem. Surface condens-ers require more auxiliary equipment andneed more maintenance.

Condensers have been widely used (usuallywith additional equipment) in controlling or-ganic emissions from petroleum refining, pe-trochemical manufacturing, drycleaning, de-creasing, and tar dipping. Refrigerated con-densation processes are being used for the re-covery of gasoline vapors at bulk terminalsand service stations.

The Technological Readiness of Control Methods

As indicated, there are a wide variety ofcontrol technologies that could be applied tothe emissions streams from oil shale proc-esses. The selection of suitable technologiesfor a given facility would be based on a num-ber of factors. The degree of control needed

for each regulated pollutant would depend onthe size of the facility; its location; the natureof the oil shale deposit; the mining, process-ing, and refining methods; the desired mix ofproducts and byproducts; the characteristicsof untreated emissions streams; and the emis-sions levels allowed by applicable environ-mental standards. The specific control equip-ment selected would be influenced by all ofthese factors, plus such considerations as theproximity to water and electrical power, theavailability of land for solid waste disposal,the labor and material requirements formaintenance, the ease of operation, the dem-onstrated reliability in similar industrial situ-ations, the availability of equipment, the ex-perience of the developer, and the cost.

An important consideration is the relativetechnological readiness of each control meth-od being considered. A developer needs confi-dence that a method can be directly trans-ferred to oil shale operations from other in-dustries without undergoing extensive R&D.All of the techniques described previouslyhave been applied to industrial processessimilar to those encountered in mining, retort-ing, and upgrading of oil shale and its prod-ucts. However, there are three characteris-tics of the potential oil shale industry that re-quire extrapolating these technologies be-yond the present levels of knowledge: thescale of oil shale operations, the physicalcharacteristics of the shale, and the nature ofthe emissions streams.

Scale of operation. —The proposed miningoperations are among the largest ever con-ceived and as such will require extraordinaryefforts to control air pollution. For example,underground mining on tracts U-a and U-bwould have mine ventilation rates as high as12 million ft3/min. Cleaning this volume of gascould be both difficult and expensive. Thelarge ventilation volume is required by mininghealth and safety regulations and cannot bereduced.

Open pit mines could be much larger thanunderground mines. Problems with fugitivedust would be increased by the larger quan-tities of solids that must be handled on the

Ch 8–Environmental Considerations ● 275

surface. Much relevant experience has beengained through the extraction and processingof other minerals such as coal, copper, ura-nium, and bauxite. The simpler control tech-niques (such as water sprays) have beenthoroughly demonstrated. However, the po-tential size of oil shale mines may createproblems for the more complex, collection-type control systems that have worked well insmaller mines. The cost of air pollution con-trol for deeply buried oil shale deposits is notknown. The amount of overburden that mustbe removed, and for which pollution controlwould be needed may be prohibitively large.

Physical characteristics of the shale.—Oilshale is a fine sedimentary material heldtogether by its kerogen content. When proc-essed in certain retorts (such as TOSCO II orLurgi-Ruhrgas) the shale can disintegrate intofine particles that are more difficult to collectand control than other mineral dusts. Otherretorts (such as Union “B” or Paraho) willproduce a coarser product with fewer prob-lems from dust. It is uncertain whether elec-trostatic precipitators will perform effective-ly in commercial-scale operations becausenot much is known about the electrical prop-erties of raw and spent shale particulate.

Characteristics of emissions streams.—Todate, the streams from small-scale versions ofdiscrete subprocesses (such as pilot retorts)have been used to obtain preliminary evalua-tions of the efficiencies of pollution controltechnologies. It is not known whether thesestreams accurately represent the streamsthat would have to be controlled in an inte-grated commercial-scale plant. For example,it is not certain that the pollutants generatedby commercial-scale retorting, when combin-ed with the pollutant streams from other sub-processes (such as upgrading), could be ade-quately controlled with conventional meth-ods. Also, the effect of volatilized traceelements on the catalysts used in the SCOTand Beavon tail-gas cleaning systems and inincinerators has not been determined, Theconcentration of some of the pollutants gener-ated by certain processes may be too low forefficient control. For example, it is unknown

whether conventional H2S control methodswill work well with the low H2S concentra-tions in the offgas from MIS retorting. Remov-al efficiencies that are too low could haveconflicted with EPA’s previous BACT stand-ards for oil shale facilities, which required99-percent total sulfur recovery, no matterhow small the concentration of sulfur com-pounds in the raw gas stream.

The technological readiness of the majorcontrol techniques is summarized in table 41.The readiness of dust control methods isshown to range from low to high, with a highconfidence in water sprays, cyclones, andscrubbers and a medium confidence in bag-houses and a low to medium confidence inelectrostatic precipitators. Similar rangesare shown for the other control techniques,The readiness of the nahcolite S02 removalprocess is rated as low because only a fewtest results have been published for its per-formance with oil shale streams. Also, thetechnology is relatively new and has not beenused extensively in other industries.

The Claus H2S process is regarded highlybecause it has a long record of successfulapplication worldwide. The SCOT andBeavon tail-gas cleaning systems have a highrating because they are generally used inconjunction with the well-established Claussystems. The fact that the feed to these sys-tems would already have been treated in aClaus unit removes some of the doubts aboutthe effects on their removal efficiencies of theunique characteristics of oil shale emissionsstreams. Combustion methods and evapora-tion controls to reduce HC and CO emissionsalso have a high rating because they shouldnot be sensitive to any great extent to thescale of operation or stream characteristics.Fugitive HC and CO emissions are much moredifficult to control.

The other control techniques are givenmedium ratings either because they have notbeen tested with oil shale streams for sus-tained periods or because the effects on theirremoval efficiencies of the projected char-acteristics of streams from commercial-scale


Table 41 .–Technological Readiness of Air Pollution Control Techniques

Pollutant and control system Readiness rating Comments

DustWater sprays High Effective and in general use with wetting agents added as needed, Low cost, Increased water needs,Road paving High Also reduces vehicle maintenance,Cyclone separators High Low cost, Effective only for large particles.Scrubbers High Low capital cost and maintenance requirements, High energy and water requirements needed for

high removal efficiency.Bag house filters Medium High efficiency, Moderate energy and maintenance requirements, Low cost. Not suitable for high-

temperature gas streams. Requires more area than other systems, Waste-disposal experiencelacking

Electrostatic precipitators Low to medium Efficiency sensitive to dust Ioading, temperature, and particle resistivity. Good removal efficiency,Low operating costs and maintenance. Good for large gas volumes. High capital cost.

H tSStretford process

Selexol, purisol, rectisol,istosoliam, fluor solvent, andother physical systemsClaus process

Tail gas cleaningSCOT processBeavon processIFP process

Medium Extensive application in refining industry, Good for large volumes of dilute gases, Being tested forMIS gases,

Medium Being tested for coal gasification streams, No experience with oil shale emissions,

High Extensive experience in several industries. Needs concentrated feed streams. High maintenanceneeds and downtime,

High Long experience with Claus plants.High Long experience with Claus plants,Medium Used with Claus plants that produce elemental sulfur May be applicable directly to retort gases,

so,Wellman-Lord process Medium Thirty Installations worldwide High capital cost. High energy requirements,Double alkali process Medium Used successfully in Japan since 1973. Waste disposal could be costly,Nahcolite ore process Low Limited but successful testing to date,

NOx

Combustion control High Can easily be designed into new plants Low capital and operating cost,Diesel exhaust control Medium Recirculation of exhaust gases can lead to maintenance problems.—HC and COCombustion control High Use of excess air easily accomplished,Evaporation control High Use of floating roof tanks is very effective but Increases capital costs,Control of fugitive emissions Low Control is difficult because of the large number of dispersed sources

SOURCE T C Borer and J W Hand /derr//f/ca/lon and ProDosed Conlro/ of A/r Pllufarrk kern 0// .Sha/e OoeraOons DreDared bv the Rockv Moufltaln Ow!slon The Pace ComDanv COOSUltafltS andEngineers Inc for OTA, October 1979

plants are still not known. In the case of theStretford process, work is underway by Occi-dental Oil Shale which, if successful, couldsignificantly improve its readiness.

In general, the control technologies appearto be fairly well-developed, and should beadaptable to the first generation of oil shaleplants. Full evaluation will not be possible un-til the methods have been tested in commer-cial-scale operations for sustained periods.

Costs of Air Pollution Control

The costs of controlling pollutants froman oil shale plant would be particularly sensi-tive to the lifetime of a project, the plant de-

sign, the scale of operation, and the extent ofemission removal required by environmentalstandards, Small-size, temporary plants suchas modular demonstration facilities wouldprobably be designed for minimum front-endcosts; therefore, control systems with smallcapital requirements would be used ratherthan those with low operating costs. The lat-ter systems would be economically attractiveover the 20-year operating life of a commer-cial plant but not over the 2- to 5-year lifetimeof a modular plant. The design of the plantwould also have an effect on the costs of con-trol. Systems to recover the byproducts sulfurand NH3 could be included in an integratedfacility, for example, not specifically for airpollution reduction but to increase plant reve-

Ch 8–Environmental Considerations . 277

nues. Additional control technologies wouldbe needed to satisfy environmental stand-ards, but overall control costs would be con-siderably less than if byproducts were not re-covered,

Another example of the effect of facilitydesign on control costs is whether the proc-esses of upgrading and refining are included.If so, other subprocesses such as retortingcould take advantage of the efficient controlsystems that are an integral part of any mod-ern refinery. If refining was not done onsite,control systems would still have to be pro-vided for the other operations. The same de-gree of removal efficiency could be achievedbut with higher costs.

The relation of the cost of pollutant controlto the degree of removal is usually not linear,i.e., the costs generally are considerablyhigher to increase a pollutant’s removal from98 to 99 percent than from 90 to 95 percent.Consequently, most control costs will bestrongly influenced by the degree of removalrequired by environmental standards. Higherremovals will be more costly for individualplants but would allow the region to accom-modate a larger industry within the frame-work of the air quality regulations.

The Denver Research Institute (DRI) re-cently estimated the costs of environmentalcontrol in the three projects for which pollut-

ant generation wasthrough 36,5 DRI’sterns were basedplans but in somecover technologies

summarized in tables 34hypothetical control sys-primarily on developercases were modified tohaving higher projected—

removal efficiencies. Two regulatory sce-narios were considered. Under the “lessstrict” scenario for particulate control in theColony plant, for example, it was assumedthat particulate reductions from pointsources would average 98.5 percent, and thatfor nonpoint sources of fugitive dust reduc-tions of 92.2 percent would be required. Theaverage particulate reduction for the plantwas assumed to be 98.3 percent, Under the“more strict” scenario, overall particulatereductions of 99.5 percent were assumed forpoint and nonpoint sources. With some differ-ences, similar control scenarios were as-sumed for other regulated pollutants, and forthe other two oil shale projects. Results ofDRI’s analysis for the “more strict” case areshown in table 42.

As can be seen, the control costs for in-dividual contaminants vary widely from proj-ect to project. In each project, however, thelargest capital and operating costs are forS O2 and particulate removal. Capital costsfor SO2 control equipment, for example, areover $25 million for the tract C-a and C-b proj-ects, which strongly rely on MIS retorting andwhich will have to clean large quantities of

Table 42.–Costs of Air Pollution Control (thousand dollars)

Colony projecta Tract C-b projectb Tract C-a prolect’

Overall Capital Operating Overall Capital O p e r a t i n g - O v e r a l l Capital Operatingreduction cost cost reduction cost cost reduction cost cost

Fugitive dust 92 2% $ 1,460 $ 564 98 4% $ 1,460 $ 577 Highd $ 1,460 $ 543Part icu lates 99. 5 % 2 9 , 4 0 0 6 , 4 9 9 8 0 . 2 % 5 , 7 9 2 1,530 99.6% 34,340 8,499s o , 99,0% 9,910 7,240 99.0% 26,210 11,187 99.0% 29,800 12,844N O , (e) (f) (f) (e) 12,866 3,882 (e) 12,866 3,882HC and” CO, 50.5% f 7,785 3,766 56.5% 240 50 89.0% 878 182

To ta l . $58,555 $18,069 $46,588 $17,226 $79,344 $25,950Cost per bbl of daily capacity $ 1,246 $ 817 $ 979Cost per bbl of oil produced – $ 1 , 1 6 — $ 0 . 9 1 — $ 0 . 9 7

a47 000 bbl/d of shale 011 syncrude b57 000 bbl/d of crude shale 011 c81 000 bb[/d Of crude shale 01[dR oads are paved Water sprays used for disposal areas eMaxlmum reduction achievable through adlustmenl of combustion conditionsfLCIW reducflofl requlremen!s because of low-temperature retorflng and use Of Iow-flltrogen fuel In combustors

SOURCE Oata adapted from Denver Research lnshfule Pred/cfed Cosk of Enwomnerrfa/ CcJmro/s for A Commerc/a/ 01/ Sha/e /rrdus(ry Vo/urne /–Arr Engmeenrrg Arra/ys/s prepared for the Department ofEnergy under confract No EP 78-S-02-5107 July 1979 pp 407-414

—— ——-

278 ● An Assessment of 011 Shale Technologies

dilute retort gas. A much lower capital invest-ment (about $10 million) is needed for the Col-ony project because the TOSCO II retorts pro-duce a much smaller volume of retort gas.

According to DRI’s analysis, the overallcosts of air pollution control range from $0.91(C-b project) to $1.16 (Colony project) per bblof oil produced These costs would have beenconsidered very high in the early 1970’s whenoil was selling for about $4/bbl. They are lesssignificant under present conditions with oilprices exceeding $30/bbl.

Pollutant Emissions

Controlled emissions rates are summarizedin tables 43 through 45 for three oil shaleprojects for which pollutant generation rateswere calculated previously. It was assumedthat the raw emissions streams from the unit

operations in each facility would be treatedin control systems similar to those for whichDRI prepared cost estimates. In the Colonyproject, for example, it was assumed thatdusty air streams from crushers and ore stor-age areas would be processed in baghouses,as would the flue gas from the retort preheat-er. Flue gases from the retort and the spentshale moisturizer would be treated in a hotprecipitator. A Stretford unit would be usedfor removal of sulfur compounds. NOX andCO emissions would be reduced by combus-tion controls on all burners, and HC emissionswould be reduced with floating-roof storagetanks and a thermal oxidizer flare system.

Table 46 summarizes the rates of pollutantemissions both for the three projects, and formodular demonstration projects proposed byUnion Oil Co. and Superior Oil. The Union andSuperior results are presented for their ac-

Table 43.–Pollutants Emitted by the Colony Development Project (pounds per hour)a

Operation Particulate so, NOx HC c o

Mining ., ., ., . . ., ., ... . .Shale preparation, ., .,Retorting, . . ., .Spent shale treatment and disposal” ~ ~ ~ . ~ ~Upgrading. ., . . ., ., . . ., .A m m o n i a a n d s u l f u r r e c o v e r y . . .P r o d u c t s t o r a g eSteam and power. ~ ~ ~ ~ ~ ~ ~ ~ . . .Hydrogen production .,

Total ., ., ...

10 0 2 5 0b 50 b

440 b

60 0 0 0 0120 140 1,430 270 5040 0 130 b 10b o

trace 10 20 10 traceo 100 0 0 00 0 0 20 00 trace 20 trace trace

10 30 80 trace 10

240 280 1,930 360 500 +

aR~~m.and.pillar Mlnlng TIJSCO II retorftng scaled to 50000 bbl/d of shale oll syncrude productionbThese emissions are not included 10 Colony PSO permlf aPPllcatlOn

SOURCE T C Borer and J W Hand /defrf/f/ca(/on and Proposed Con/ro/ of AM Pollufarrfs From 0(/ Shale Operations prepared by the Rocky MountainOwlsion, The Pace Company Consultants and Eng[neers Inc for OTA October 1979

Table 44.–Pollutants Emitted by the Rio Blanco Project on Tract C-a (pounds per hour)a

Operation Particulate so, NOx HC c oMining ., . ., 20 0 340 6 435Shale preparation. ., . ., . . . 26 0 0 0 0R e t o r t i n g . . , 92 52 320 98 0Spent shale treatment and disposal’ ~ ~ ~ ~ ~ 32 0 0 0 0Upgrading. ., ., ., ., ., 6 0 6 13 0Ammonia and sulfur recovery, ... ., . 0 0 0 0 0Product storage. ., 0 0 0 105 0Steam and power ., ., . . . ~ 210 250 1,220 13 0Hydrogen production ., ., – — — — —

Total ., ., ., . . ., ., ... - 386 302 1,886 235 435

auflde@~Ound Mlnlng M [s and Tosco II abovegfound retorting scaled 1050,000 bblld of shale oil Swcrude woduchofl

SOURCE T C Borer and J W Hand. /derrf/l/ca(/orr and %oposed Confro/ O( AM f’o//ufanfs from 0// S/ra/e Opera(/errs, prepared by the Rocky MountainOwlslon The Pace Company Consultants and Engineers Inc for OTA October 1979


Table 45.–Pollutants Emitted by the Occidental Operation on Tract C-b (pounds per hour)a

Operation Particulate so, NOx HC c o

Mining 20 0 300 10 180R a w s h a l e d i s p o s a l 80 0 100 10 0R e t o r t i n g , 10 0 0 0 0Upgrading 10 10 80 trace 10Ammonia and sulfur recovery. 0 240 0 0 0P r o d u c t s t o r a g e 0 0 0 80 0S t e a m a n d p o w e r 20 trace 2,800 b o 0H y d r o g e n p r o d u c t i o n 80 20 220 20 20

Total 220 270 3,500 120 210

a Underground mlnlng MIS retofilng scaled 1050000 bbl d of shale 011 syncrude productionbAssumes gas turbines for power generation

SOURCE T C Borer and J W Hand (der?hflcallon and Proposed Cofl(ro/ of AU Po//uranrs from 0// Shale Operal/ons prepared by the Rocky MountainDlvlslon The Pace Company Consultants and Engineers lnc for OTA October 1979

Table 46.–A Summary of Emissions Rates From Five Proposed Oil Shale Projects

Pollutant emissions, lb/hr

Project and retortinq technology Shale oil production P a r t i c u l a t e s S O2 NOx HC co

ColonyTOSCO I I aboveground retort 50,000 bbl/d syncrude 240 280 1,930 360 500Rio BlancoMIS plus Lurgi-Ruhrgas aboveground retort 50,000 bbl/d syncrude 386 302 1,886 235 435OccidentalMIS 50,000 bbl/d syncrude 220 270 3,500 120 210SuperiorSuperior retort plus nahcolite and alumina recovery 11,500 bbl/d crude 75 347 172 20 47UnionUnion Oil ‘ ‘B’ aboveground retort 9,000 bbl/d crude 35 81 100 59 43

SOURCE T C Borer and J W Hand /deflflf/cat/on and ProDosed ConVo/ ot AK Pol/u(an(s From 0// Sha/e Operations prepared by the Rocky Mounlain Olvlslon The pace Company Consultants and Enavneers Inc for OTA October 1979

tual design conditions, which provide aboutone-fifth of the shale oil produced by theother projects. Because emissions rates arenot always directly related to plant capacity,the much smaller modular projects are notexpected to have equivalently lower rates ofemissions. In fact, S02 release from theSuperior project (11,500 bbl/d) is expected tobe significantly higher than from the three50,000-bbl/d projects. In part, the high rate ofSuperior’s emissions is related to the natureof its process, which includes unique sub-processes for the recovery of nahcolite andalumina. They also arise from the scale ofoperation, which does not encourage the useof large-scale, costly controls that would becost-effective for the larger operations at Col-ony and on the lease tracts.

EPA has granted PSD permits for the Col-ony and Union projects at the levels of opera-tion listed above. Permits have also been

granted for modular-scale operations on C-a(1,000 bbl/d) and C-b (5,000 bbl/d). EPA there-fore expects the projected emissions rates atthese production levels to comply with all ap-plicable Federal and State emissions regula-tions. However, it should be noted that theevaluation of the environmental impacts of oilshale development also requires a considera-tion of the effects of the emitted pollutants onambient air quality, which is protected byNAAQS and PSD limitations. Without large-scale operating facilities, the effects of emis-sions on air quality can only be predicted byusing mathematical models.

Dispersion Modeling

The Nature of Dispersion Models

The Clean Air Act, through the regulationspromulgated for attainment of NAAQS and

-——


PSD standards, requires the use of mathe-matical models to relate the emissions from asource and the resulting incremental impactthat the source causes on a point some dis-tance away. At present, models are EPA’stool for enforcing the provisions of the Actand are the only means for predicting long-range impacts of oil shale emissions on am-bient air quality in the oil shale area and inneighboring regions.

Air quality models are mathematical de-scriptions of the physical and chemical proc-esses of transport, diffusion, and transforma-tion that affect pollutants emitted into the at-mosphere. In these models, specified emis-sions rates and atmospheric parameters areused as input data, and the effects on ground-level pollutant concentration and visibility ofplume rise, dispersion, chemical reaction,and deposition are simulated. Some modelsare designed to simulate small-scale airflowpatterns over complex terrain within a fewmiles of the pollution source. These near-source models can predict the effects of oilshale emissions in the immediate vicinity ofthe plant. They are used during preconstruc-tion review to indicate the facility’s expectedcompliance with PSD regulations.

Other models simulate broader airflowbehavior over distances of hundreds of miles.These regional dispersion models could beused to simulate the effects on a large area ofan entire industry, including numerous indi-vidual plants. Regional-scale models can beused to predict impacts on air quality in near-by Class I areas. The time scale of the inputdata and the output predictions should be ap-propriate to the size of the region being simu-lated. Small increments can be used for near-source modeling; increments of several daysfor regional dispersion models.

Most models incorporate a series of com-putational modules, as shown in figure 60. Amajor difference between the models lies inthe manner in which the input data are ma-nipulated and in the application of the com-putational modules. Usually, not all of themodules are used in any given model. Near-source models need to simulate complex air

flow near prominent terrain features, but canusually ignore chemical reaction, aerosolcoagulation, deposition, and visibility effects,which generally become most significant overlarger distances and longer time periods. Incontrast, regional models can sometimes ig-nore terrain features, but must consider long-range atmospheric conditions and their ef-fects on chemical reaction, coagulation, depo-sition, and visibility.

A key feature that must be considered inevaluating the use of any model to estimatecompliance with NAAQS and PSD regula-tions is its ability to simulate worst case con-ditions, which are those meteorological condi-tions that lead to the highest ground-level con-centrations. These conditions vary dependingon the location of the emitting facility, its con-figuration, and the nature of the surroundingterrain. Some candidate worst case condi-tions for the oil shale region include:

●

●

●

●

●

It

several days of atmospheric stagnationduring which emissions would accumu-late under an inversion in a valley;a looping stack-gas plume that wouldbring maximum pollutant concentrationsdirectly to ground level;a plume trapped in a stable atmosphericlayer and transported essentially intactto nearby high terrain;fumigation, when a plume is transportedfrom a stable layer at medium heights tothe ground level. (Fumigation conditionsnormally persist for less than an hour.They are usually the worst case foremissions released from stacks); andmoderate wind conditions in which astable polluted layer spreads uniformlyand causes visibility reduction over alarge area. (This is usually the worstcase for emissions released near groundlevel.)

is reasonable to assume that some worstcase conditions (e. g., several days of atmos-pheric stagnation) could occur several timesa year, while others might occur only a fewtimes over the lifetime of an oil shale projectand might not be detected during a 1- to 3-

Ch 8–Environmental Considerations 281

Figure 60.—Computation Modules in AtmosphericDispersion Models

‘m’ss’””ra’es~Background

Plume risew

Source characteristicsmodule

Atmospheric conditions !* t

+ :%?: IDispersionWmdfleld and other meteorological

data1 I

I+,

Reaction kmetlcsChemical reaction

Pollutant characteristicsmodule

II $I

I

I Aerosol coagulationmcdule It

Airborne concentrationmodule

1 i

Visibility module Depositionlwocass

Y(wet & dry)module

GROUND

S O U R C E E G Walther, et al T h e Eva/uaf/on of AI{ Oua//fy CJ/spers/on M o d e //rrg for 01/ Sfra/e Deve/opmerrt prepared for OTA by the John Mu Ir ln -stltute for Environmental Studies, Inc October 1979

year environmental monitoring program priorto the start of constructing a project,

Gaussian models* and grid models arecommonly used to simulate near-source dis-persion effects. Gaussian models were devel-oped for the relatively simple air flow pat-terns over flat terrain. They can be modified,with a significant loss of accuracy, to simu-late complex flow around terrain obstacles,and up and down valley floors. They cansimulate some worst-case conditions, such asvery low wind speeds, but not looping plumesor variations in wind direction with in-

*A Gaussian model is based on a theoretical pattern of fre-quency dlstrihution in which a bell-shaped (or normal) curveshows the d is! ribu lion of probabi]i ty associated with differentIsues of a va riahle quantit y— in this case pollutant concentra-tions.

creasing altitude. Their mathematical ex-pressions are relatively simple, and can oftenbe run on a hand calculator. However, mostGaussian models rely on straight-line simula-tion of pollutant trajectories and do not con-sider spatial, temporal, and vertical vari-ations in atmospheric conditions. As a resultthey tend to overestimate ground-level pollut-ant concentrations at distances greater than30 miles from the source.

Numerical or non-Gaussian models such asgrid models are more useful for simulatingnear-source complexities. They estimate pol-lutant concentrations at each point in a three-dimensional pattern overlying the region ofinterest. For detailed computations and highaccuracy, the spacing of the grid points mustbe small and the time interval between suc-cessive iterations must be short. Because ofthese characteristics and due to the complexmathematical manipulations used, grid mod-els require the use of high-speed computers,and input data must include highly detailedwind field information. Such information isusually not easily obtainable without a veryexpensive atmospheric monitoring program.

Grid models can also be used for simulat-ing long-range effects over a large region ifinformation is available on conditions in theupper atmosphere. In these applications, ter-rain details usually become less important.Complex terrain features, which must be ac-curately simulated in near-source modeling,can be simulated through use of an averageroughness factor. However, because of thelonger timespan being modeled, slow chemi-cal reactions that involve, for example, SO2

and NOX, become significant. Aerosol sizedistribution (critical in visibility analysis) andthe contributions of other polluting sourcesare also important.

A critical problem in applying regionalmodels is caused by the fact that pollutantspass through several meteorological regimeson their path from source to deposition point.Budget models, which divide the affected re-gion into discrete air cells, can be usefulunder these circumstances because they dealonly with the flow of air into and out of one

63-898 0 - 8CI - 19


cell and with the reactions that occur withinthe cell. If the cell size or iteration incrementis too large, important details such as rapiddeposition in transition areas between low-lands and mountains may be missed. Thesedeficiencies can be compensated for by usingtime trajectory models, numerical fluid flowmodels, box models, or sector averagemodels.

Problems With Dispersion Modeling inthe Oil Shale Region

Modeling of oil shale facilities presents anumber of problems because of the topogra-phy and meteorology of the oil shale region,the chemistry of oil shale emissions, and theunknown quantities of emissions expectedfrom commercial-size facilities. Dispersionmodels developed to date have been primarilyfor flat terrain. The terrain of the oil shaleregion is very complex, including many val-leys and canyons. Furthermore, some devel-opers have proposed siting their plants in themiddle of a cliff face or near a canyon rim.Simulating this geometry presents uniquemodeling problems. In addition, the chemistryof oil shale emissions is quite different fromthat of powerplants in urban areas and maylead to increased oxidant formation through

photochemical reactions between HC andNOX. * Thus, the conventional set of reactionsused to model urban photochemistry wouldhave to be augmented to accurately simulatethe oil shale situation.

Also, oil shale operations emit much fugi-tive dust. Proper modeling of these emissionsmust consider the role of wind in creating theemissions as well as its role in dispersingthem. In the mountainous areas downwind ofoil shale plants, precipitation may cause thewet deposition of the oil shale emission, thuslessening the regional transport of visibilityimpacts but increasing impacts on ground-level ecological systems.

Another problem in developing accuratedispersion predictions for oil shale facilitiesis the fact that the input data on emissionscan only be estimated, since no commercial-ize plants have yet been built. This problemis exemplified in table 47, which presents asummary of emissions data used in severalearly modeling studies. These studies variedwidely with respect to the quantities of theemissions that were assumed for varioustypes of retorting technologies and the levels

*Photochemical reactions are induced in the atmosphere byu] traviolet radiation from the Sun.

Table 47.–A Comparison of Atmospheric Emissions Used in Modeling Studies

Total emissions (lb/hr)

Production capacityStudy and site Retort (bbl/day) Study date so* NOx HC Particulates

BattelleColorado TOSCO II 50,000 1973 143 732 300 1,285

Federal Energy AdministrationColorado TOSCO II 50,000 1974 1,332 1,464 317 741

Stanford Research InstituteColorado and Utah TOSCO II 100.000 1975 3,111 4,078 600 650

ColonyColorado TOSCO II 63,000 1975 282 1,806 324 829

317 1,746 304 842Tract C-b

Colorado TOSCO II 45,000 1976 267 1,634 262 776353 1,894 313 968

Tract C-aColorado TOSCO II 6,000 1976 26 322 112 148

56,000 265 994 185 573Tracts U-a and U-b

Utah Paraho 10,000 1976 8.4 108 0.88 6850,000 148 1,369 55 452

SOURCE Adapled from the Enwronmenlal Prolectlon Agency A f’relvmrrary Assessmertrof fhe Env/ronrnerUa/ hnpacfs from (7// .Sha/e L7eve/oprnenfs July 1977 p 110


of production, Even if the estimates for theTOSCO II operations are scaled to the sameproduction capacity, they vary by as much asan order of magnitude. Much of this discrep-ancy is associated with assumptions by ana-lysts about environmental-control technol-ogies and their efficiencies, Although individ-ual modeling runs provide some insight intosite-specific air quality effects for a givenretort capacity under specific meteorologicalconditions, substantial variations in the in-put-data assumptions prohibit comparing dif-ferent retorts, levels of development, andplant locations,

The Application of Dispersion Models toOil Shale Facilities

The application of flat-terrain models tothe oil shale region requires many adapta-tions in order to provide rough estimates ofthe impacts of a particular facility on am-bient air quality. Near-source models havebeen used to estimate the effects of emissionsfrom single proposed facilities. Such effectsmust be modeled to qualify for a PSD permitfrom EPA. A preliminary study has also beenundertaken by EPA to estimate the regionaleffects of several oil shale plants. Since onlyestimates are available for the levels of emis-sions from commercial-size facilities, model-ing results can only be considered approx-ima te,

One example of the use of near-sourcemodels was a study performed for Colony De-velopment by Battelle Northwest Laborato-ries. Colony was considering two plant loca-tions: one in the valley of Parachute Creek,the other on an adjacent site atop Roan Pla-teau. A model predicted that NOX concentra-tions near the valley site would exceed thenational standards; SO 2 and particulatewould barely meet the standards. The modelpredicted that the corresponding pollutionlevels near the plateau site would be an orderof magnitude lower. Because of this predic-tion, Colony selected the plateau location.67

Another example is the work undertakenfor Federal lease tract C-a. Models were runfor widely different operating conditions, in-

cluding completely different retorting tech-nologies and levels of operations. As noted involume II, the tract C-a lessees originally con-templated open pit mining and abovegroundretorting in a combination of TOSCO II anddirectly heated retorts (like the Paraho kiln).In phase I, a single TOSCO II retort would beused to produce from 4,500 to 9,000 bbl/d ofshale oil. In phase II, several TOSCO II anddirectly heated retorts would be used to pro-duce up to 55,800 bbl/d. The lessees con-ducted modeling studies that estimated theair quality impacts of each developmentphase. Both long- and short-term effects werestudied with an EPA Gaussian Valley model,modified to account for the mixing-layer ef-fects of rough terrain and for inversion epi-sodes. Results were reported in the DDP inMarch 1976.’

The lessees subsequently adopted a newplan that was also phased but which involvedunderground mining and MIS processing. Thelessees prepared a revised DDP and per-formed new modeling studies. Two mathe-matical models were used: long-term (annual)effects were studied with an EPA model modi-fied for high terrain and atmospheric stabil-ity; shorter term (3 to 24 hours) effects werestudied with a modified Gaussian model. Asin the earlier modeling studies, meteorologi-cal measurements made on the tract wereused as input data to the models. Worst casepredictions for both phases were reported inthe revised DDP in May 1977.9

The results of both sets of studies are re-ported in table 48. Predictions are presentedfor both offtract ambient air quality and forthe incremental quality degradation. Alsoshown are the relevant NAAQS (either pri-mary or secondary, depending on which ismore stringent), the Federal PSD incrementlimitations, and the corresponding Coloradoambient air standards. All standards shownare those that currently apply to the oil shaleregion.

The models predicted that both phases ofboth plans should be in compliance with ap-plicable standards, However, the off tractconcentration of nonmethane HC was pre-

. —


Table 48.–Modeling Results for Federal Oil Shale Lease Tract C-a

Revised DDP (May 1977) Original DDP(March 1976)

National standards Colorado standards Ofttract ambient air Offtract increment Otftract ambient air Ofttract increment

Averag- PSO increment Ambient PSD Increment Phase lb Phase IIc Phase lb Phase IIc Phase ldPhase IIe Phase Id Phase IIe

Pollutant ing time NAAQSa Class II Air Category II MIS MIS/TOSCO II MIS MIS/TOSCO II TOSCO II Aboveground TOSCO II Aboveground

S o2 Annual 80 20 80 20 8 4 8 3 2 2 7 10 1124-hour

1365

2365 91 102 8 5 3 23 28

3-hour 51214

1,300 70019

512 352 25 30 20NOX

91Annual 100 None 100

103 82 94None 8 13 6

Particulates Annual11

6016 10 14

19 458

19 9 12 0 3 3 16 2224-hour 150 37 150 37 10

1012 1 3 34 41 22 29

NonmethaneH Cf 3-hour 160 None 160 None 65 90 0.3 25 221

Lead Quarterly129

15 None156 64

15 None — —

o ,— —

l-hour

—

240

—

None

— —

160 None — — — — — — — —

bcapacll 4 0 0 0 bbl/d (MIS)aslrlcter Ot primary and secondary standards\

ccapaclty 57000 bbl/d (MIS) + 19.000 (TOSCO 11) dcapaclty 9 0 0 0 bbl/d (TOSCO l{)ecapaclly 55800 bbl/d (TOSCO II and. e 9 ~ paraho) Not a standard a guide to show achievement of the O, standard

SOURCE Data adapted from onglnal and revised detaded development plan for tract C.a See refs 8-9

dieted to exceed the Federal and State guide-lines during Phase I of the old plan. It shouldalso be noted that in the old plan the off tractincrement for HC is only slightly less than the3-hour average guideline. In the new plan,however, offsite concentrations and incre-ments for both phases are well within compli-ance.

With respect to the effect of scale of opera-tion, the table indicates that, in general, theimpact of the smaller scale phases of bothplans are nearly equal to those of the corre-sponding larger scale phases. This is ex-plained by the lessees’ intent to use the firstphase of each plan to obtain reliable data onemissions levels and dispersion characteris-tics, and then to use these data to design con-trol technologies for the subsequent commer-cial phases. Also, final commitment to thecommercial operations was not to be madeuntil technical and economic feasibility stud-ies, based on operating data obtained in theearly phases, could be completed. To avoidunnecessary capital commitment in the initialphases, the first facilities were designed forminimum investment requirements.

It is difficult to interpret the technology-related effects of old and new plans for tractC-a because the levels of operation are dif-ferent, and different models were used tosimulate air quality impacts. However, aqualitative comparison is possible. The tableindicates that the original concept (open pitmining and aboveground retorting) wouldhave caused higher ambient levels of SO2,

particulate, and nonmethane HC and lowerlevels of NOX than the revised concept (un-derground mining, MIS, and limited above--ground retorting). Although the revised facil-ity is to have 36 percent more shale oil capac-ity, ambient air impacts and PSD incrementsare generally lower.

With respect to regional modeling, EPA hasused a modified Gaussian model to predictthe effects on air quality at the Flat TopsWilderness Area of oil shale operations at theColony site (50,000 bbl/d), on tract C-a (1,000bbl/d), on tract C-b (5,000 bbl/d), and at theUnion site (9,000 bbl/d). * The total shale oilproduction was about 65,000 bbl/d, of whichabout 77 percent was assumed to come fromColony’s TOSCO II retorts. The model waslimited in that only one source could be mod-eled at a time, so four runs were needed tomodel the industry. In each run it was as-sumed that the wind was blowing from thesource directly to Flat Tops. The cumulativeimpacts of the industry were estimated byadding the increments from each source. Re-sults indicated that about 20 percent of thePSD increment for particulate would be con-sumed, and about one-third of the S02 incre-ment. Simple linear scaling would indicatethat the industry would be limited to about217,OOO bbl/d by the PSD restrictions on S02,and to about 325,000 bbl/d by the particulatePSD.

*Flat Tops Wilderness Area is approximately 65 miles fromtract C-a, and 50 miles from tract C-b and the proposed Colonyand Union projects.


Such scaling is highly inaccurate for anumber of reasons. First, Gaussian modelstend to overestimate ground-level concentra-tions of SO2, because they do not allow for for-mation of sulfate particles from S02 and theirsubsequent deposition. Second, it is impossi-ble for the wind to be blowing from four di-rections at the same time. Third, the pro-jected SO2 and particulate concentrations atFlat Tops were affected strongly by the Col-ony project, which is predicted to emit moreS O2 and particulate than the technologiesproposed by tract C-a, tract C-b, and Union. Itwas EPA’s opinion that a better estimatewould be that as much as 400,000 bbl/d couldbe accommodated in the Piceance basin bythe PSD standards for Flat Tops.10 EPA’sanalysis did not consider any project in theUinta basin, the eastern edge of which isabout 95 miles from Flat Tops. Therefore,there are no estimates available of the addi-tional capacity that could be installed in Utahwithout exceeding the PSD restrictions atFlat Tops. The proposed Dinosaur NationalMonument, about 50 miles north of tracts U-aand U-b, could also limit operations in Utah ifit is designated as a Class I area. *

Evaluation of Modeling Efforts

Table 49 lists the models used by oil shaledevelopers to support PSD applications fortheir projects. EPA has accepted the resultsof these studies as evidence of expected com-pliance with air quality regulations, and PSDpermits have been granted. Note that, with

*A Department of the Interior task force in September 1979recommended Iha t the Dinosaur Nntional N!onument be desig-na led as a Class I n rcn.

the exception of the Colony project, onlysmall-scale plants were modeled. Some devel-opers, such as Rio Blanco and the tract C-blessees, have also modeled the effects of com-mercial-scale operations at the same loca-tions. However, EPA has not yet evaluatedthe results of these studies for adequacyunder the PSD-permitting process.

The widespread reliance on the GaussianValley model should also be noted. All of thedevelopers relied on this model for simulationof near-source effects. PSD permits weregranted for the projects because the modelsrepresented the state-of-the-art of near-source dispersion, and because most of theprojects were of relatively small scale. Themodels used are deficient in many respects.For example, the Gaussian Valley model canbe used for estimating pollutant dispersion instable atmospheric conditions in complex ter-rain, However, as described previously, ittends to overestimate SO2 concentrations andcannot handle most worst-case conditions.Also, Gaussian models when applied to com-plex terrain introduce error by a factor of 5to 10 when computing concentrations on high-terrain features. This factor of error in themodel’s capability, coupled with a 2 to 5 errorfactor in estimating emission concentration,increases the level of uncertainty in deter-mining compliance with air quality stand-ards. In a recent workshop conducted by theNational Commission on Air Quality, it wasrecommended that the Valley model be usedonly for screening purposes in complex ter-rain situations, and that it not be used for de-termination of compliance with NAAQS orPSD standards. ’

Table 49.–Models Used in Support of PSD Applications for Oil Shale Projects—

Maximum shaleProject Retorting technology 011 production Model used

Colony Development Operation TOSCO II 46,000 bbl/d Gaussian Valley model, modified for rough terrain, to studyeffects of long-distance transport. Box model for effects oftrapping inversions near source.

Union 011 Co Long Ridge Union ‘‘B’ 9,000 bbl/d Modified Gaussian Valley model.RIO Blanco 011 Shale (tract C-a) Modular MIS 1,000 bbl/d Modified Gaussian Valley modelC-b Shale 011 Venture (tract C-b) Modular MIS 5,000 bbl/d Modified Gaussian Valley modelOccidental 011 Shale Inc Logan Wash Modular MIS 5,000 bbl/d Modified Gaussian Valley model

SOURCE Ofllce of Technology Assessment


Other models that have been used to pre-dict emissions from proposed oil shale facil-ities include the CRSTER and the AQPUF2. *The CRSTER model is generally used by EPAto simulate effects of emissions from tallstacks in complex terrain. It tends to overesti-mate pollutant concentrations where plumesare intercepted by terrain features higherthan the plume rise height, ” The CRSTERmodel used by Rio Blanco in their DDP couldnot handle fugitive dust emissions, gravita-tional settling, separated stacks, chemicalreactions in the plume, some high-terrainfeatures, and a change of wind direction withheight. All of these variables are important toaccurate prediction of some near-source ef-fects. The AQPUF2 model also used by RioBlanco in their DDP for short-term studieswas better able to simulate plume behavior incomplex wind fields and to compare the ef-fects of emitting stacks a significant distanceapart from each other. The effect of windspeed on the generation of fugitive emissionswas not simulated in any of the models used.

Research and Development Needs

The problems of modeling pollutant disper-sion in the oil shale area are also encounteredin other regions with complex terrain, suchas the Ohio River Valley and the Four Cornersarea of Colorado, Utah, Arizona, and NewMexico. The Dispersion Modeling Panel at arecent workshop conducted by the NationalCommission on Air Quality recommended thefollowing research on the modeling of atmos-pheric dispersion in such areas:]]

. Regional models should be developedthat can simulate effects at long dis-tances from the sources, For SO2, thesedistances could approach 600 miles. Up-wind pollutant concentrations should bedetermined and used as input data to themodels.

● The regional models should allow the useof a fine-resolution grid spacing near thepollution sources, and a coarse spacingat greater distances. Given this capabil-

*CRSrI’ER is a Gaussian model developed by EPA, AQPUF2 isa segmented-plume Gaussian rough-terrain model,

●

●

ity, near-source effects and more distantimpacts could be modeled simultane-ously.Chemical reaction and deposition mod-ules should be included wherever themodeled region is large enough for theseeffects to be significant.A simulation of photochemical oxidantformation and of the conversion of SO2 tosulfates should be combined in the samemodel.

More specific research needs can be iden-tified for the oil shale region. The models usedto date have given only rough estimates of theimpacts of oil shale development on ambientair quality. Because the models are only ap-proximations, they cannot provide definitiveanswers to crucial air quality questions. Nocommercial-scale oil shale facilities exist thatcould supply the data for verification. Fur-thermore, essential information is lacking onmeteorological conditions in locations otherthan in the immediate vicinities of some of theproposed development sites.

The models themselves need to be im-proved for the oil shale region. Near-sourcemodels need to be modified to better simulatechemical reaction, coagulation, deposition,and visibility effects of oil shale plumes dur-ing stagnation periods. Models are also need-ed that can simulate the effects that severalfacilities would have on air quality in a smallarea having complex terrain. This capabilitywill be critical in evaluating the effects ofsecond-generation oil shale plants. A goodsite for analysis would be the southeasterncorner of the Piceance basin. PSD permitshave already been issued for three projects inthis area, which contains much of the private-ly owned oil shale land in Colorado. More ap-plications may be submitted in the near fu-ture. Models are also needed that can simu-late the effects of wind rate on generationand transportation of fugitive dust from stor-age and disposal areas.

Many of these improvements also areneeded by regional dispersion models. In par-ticular, existing models should be modified tosimulate long-range visibility effects of oil


shale plumes. This capability will be requiredto respond to the forthcoming visibility reg-ulations. Visibility models exist that deal withthe formation of aerosols and particulatefrom SO2 and NOX, but these models are ap-plicable to examinations of urban smog andpowerplant emissions. Greater emphasiswould have to be given to HC reactions inorder to modify these models to simulate oilshale plume effects.

The need to model the cumulative impactson regional air quality is particularly impor-tant. Each scenario should include specifica-tions for the locations of oil shale plants, acharacterization of their pollution controltechnologies, and estimates of their emissionsrates. The region’s meteorology would have tobe accurately characterized over periods ofseveral days, or for at least the time requiredfor the full impact of the combined emissionsto be experienced in nearby Class I areas.Computational modules would have to be in-cluded for the effects of emissions, disper-sion, aerosol dynamics, chemical reaction,deposition, and visibility, The model alsoshould handle differences between daytimeand nighttime mixing heights and atmos-pheric chemistry, In addition, the regionalmodels would have to be validated, eitherthrough tracer studies in the oil shale regionitself or by examining the ability of the modelto simulate the behavior of emissions from agroup of coal-fired powerplants or smelters.

One type of tracer study that could be usedto validate the models is the release of sulfurhexafluoride, or a similar tracer compound,followed by the monitoring of tracer concen-trations at numerous ground-level locations.A dense pattern of monitoring stations wouldbe needed to locate maximum concentrations,because the widely varying wind patterns inthe oil shale region prevent any attempt tocharacterize total wind fields by interpolat-ing data from a few stations. Baseline meas-urements of pollutant concentrations and vis-ibility parameters upwind from the sourcewould be required to accurately simulate thechemical interactions of the tracer plumes.

The state-of-the-art of near-source and re-gional dispersion modeling is being advancedby R&D programs under the sponsorship ofEPA and other organizations. The followingprojects are of particular importance to eval-uating the air quality impacts of oil shaleplants.

EPA is funding a project with DRI tocombine information on oil shale emis-sions and meteorology, and to use region-al models to assess air impacts from sev-eral commercial-size oil shale facilities.The model will also handle emissionsfrom other sources such as traffic, pow-erplants, and other mineral-processingplants.EPA is funding a project with the Univer-sity of Minnesota to develop a simplemodel of aerosol dynamics, includingconversion of gases to aerosols, that maybe of use in evaluating the effects of thechemistry of oil shale plumes on visibili-ty.Los Alamos Scientific Laboratory isfunding a project with the John Muir In-stitute for Environmental Studies to de-velop a multiple-source visibility modelthat could be applied to regional disper-sion studies in the oil shale area. In arelated study, the University of Wyomingand Los Alamos are funding a project todevelop a regional haze model whichmight be useful in assessing visibility ef-fects of oil shale plumes.EPA is funding an in-house project at Re-search Triangle Park to develop a multi-ple-layer atmospheric model that is de-signed to explain regional O3 patterns inthe Northeast. It may also be useful forexplaining the high O3 concentrationsencountered in the oil shale area.EPA is funding a project with SystemsApplications, Inc., to model the air quali-ty effects of oil shale industries withcapacities of 400,000 bbl/d (includingtract C-a, tract C-b, Colony, Union, Supe-rior, tract U-a, and tract U-b) and 1 mil-lion bbl/d. The model will handle all


sources simultaneously and will modelvisibility effects. The project is designedas an extension to EPA’s early regionalmodeling exercise. Its major objective isto estimate cumulative impacts on exist-ing and proposed Class I areas such asFlat Tops.

A Summary of Issues and Policy Options

Issues

INADEQUATE INFORMATION

Extensive work has been undertaken in thepublic and private sectors to determine thedegree of pollution control that will have to beused by oil shale facilities to protect air quali-ty. However, no large-scale facilities exist toverify the predictions arising from this work.Furthermore, the dispersion characteristicsof treated emissions streams cannot be accu-rately predicted because modeling and moni-toring methods are not yet adequate. In itspresent state of development, modeling canbe used, but the results must be carefully in-terpreted. Therefore, it is not known what im-pacts oil shale unit operations will have onair quality at various shale oil production lev-els. Specific areas of uncertainty and some

suggested R&D responses are summarized intable 50. Some of the uncertainties, such asdispersion behavior, could be reduced some-what by means of laboratory studies andcomputer simulations; others, such as theperformance characteristics of control tech-nologies, may necessitate full-size facilitiesand extended programs under actual operat-ing conditions. It is important that emissionsstudies and monitoring and modeling pro-grams keep pace with oil shale development.

LIMITS ON OIL SHALE DEVELOPMENTThe atmosphere has a finite carrying ca-

pacity; that is, it can only disperse limitedquantities of airborne pollutants. The effectof the carrying capacity of air in the oil shaleregion on the long-term development potentialof oil shale resources is unknown. A crude re-gional modeling study undertaken by EPA hasindicated that an industry of 200,000 t o400,000 bbl/d could probably be controlled tomeet PSD regulations in the Piceance basin. Itis unclear whether a larger industry (theorder of 1 million bbl/d) could be establishedin the Piceance and Uinta basins without vio-lating air quality regulations.

Additional questions arise regarding themanner in which PSD increments will be allo-

Performance of controltechnologies

Dispersion behavior

Trace element behavior

Table 50.–Areas of Inadequate Information and Suggested R&D Responses

Area of uncertainty Relevance Research need

Baseline air quality conditions and Inhibits accurate modeling of emis- Regional characterization studies, including measurement of visibility andmeteorological characteristics sions dispersion and deposition concentrations of criteria and noncriteria pollutants and determination of

meteorology, especially with respect to worst case conditions.

Emissions characteristics Prevents evaluation of control effec- Characterization of stream and fugltive emissions, beginning with pilot-planttiveness and cost and reduces studies and continuing with first-generation modules and pioneer commercial-modeling accuracy. size plants. Streams from individual unit operations should be Integrated to

simulate expected commercial conditions.

Inhibits modeling and cost Additional pilot-plant and demonstration-plant programs.estimation.

Inhibits evaluation of near-source and Improvement in modeling and monitoring techniques for complex terrain,regional air quality impacts. including development and validation of near-source and regional dispersion

models Models to be validated for the terrain and meteorology of the 011 shaleregion and for emissions similar to those expected from 011 shale operations.

Inhibits evaluation of the effects of 011 Monitoring of trace element concentrations in process feed streams, treatedshale development on human health, emissions streams, and fugitive emissions. Examination of the effects ofplants, and animals. conventional control technologies on trace elements. Determination of the

relationships between trace element concentrations in soils and plants andnutritional problems. Development of indicator species Studies of the synergis-tic effects of trace elements on vegetation

SOURCE Ofl[ce of Technology Assessment


cated to potential oil shale developers. The oilshale region has been designated Class II, butseveral Class I areas exist nearby that couldbe affected by oil shale operations. The lawprohibits any facility to exceed the PSD limi-tation in any area, including the area inwhich the facility is to be sited and any adja-cent areas, Thus, oil shale developers willhave to demonstrate that their facilities willsatisfy both Class II PSD standards and ClassI standards.

Under the present regulatory structure,PSD increments are allocated on a first-come,first-serve basis. The first oil shale plants in agiven area could exhaust the entire incre-ments. If this occurs, subsequent developers,who might be delayed by the preliminary sta-tus of their processing technologies, will notbe able to locate in the same area, regardlessof the efficiency of their air quality controlstrategies.

Under the provisions of the Act, new facil-ities can be located in a polluted area if theyare able to offset their emissions by reducingthe emissions of other industrial plants in thesame area. This strategy may be feasible inurban industrialized areas, especially whereexisting facilities are old and do not employstate-of-the-art air pollution control methods.It is not applicable to the oil shale areas atpresent because there are few industrial fa-cilities against which to offset new emissions.It probably will continue to be inapplicable asthe area industrializes, because any newplants will be built with the best availablecontrol technologies to reduce emissions tominimum levels. A subsequent oil shale devel-oper would thus be forced to improve on thesecontrol methods. It is uncertain whether thiscould be done at reasonable cost.

These constraints could result in each oilshale plant being surrounded by a bufferzone in which no additional industrial activ-ities (including oil shale development) wouldbe allowed. Without reliable regional airquality modeling studies, it is impossible topredict the width of these buffer zones, How-ever, it is very possible that such zones couldsubstantially reduce the area of a given oil

shale basin that could be developed, and thuslimit the ultimate size of the industry thatcould operate within the basin,

UNDEFINED REGULATIONS

The Clean Air Act stipulates a need to pro-tect visibility in Federal mandatory Class Iareas. While regulations are to be promul-gated by EPA by November 1980, and by theStates by August 1981, uncertainties still ex-ist as to the potential implications for oilshale development in regard to the siting offuture oil shale facilities. In addition, EPA ispresently developing incremental PSD stand-ards for HC, CO, O3, NOX, and lead. Oil shalefacilities will have to comply with these newstandards.

Another area of uncertainty concernsemission standards for hazardous air pollut-ants under section 112 of the Clean Air Act,To date, the emissions that are regulated areasbestos, vinyl chloride, mercury, and berylli-um. Controls have been required for indus-tries that produce these substances at highrates. To date, the oil shale industry has notbeen included under the regulations for thesepollutants because it is expected that theywill be generated at low levels, if at all. How-ever, EPA is in the process of developing haz-ardous emissions standards for POM, arse-nic, and possibly other substances. It does notappear at this time that these substances willbe regulated for oil shale operations, but theregulations could be applied to oil shale if thesubstances are found in the emissionsstreams during future characterization stud-ies. Furthermore, it is also possible that addi-tional regulations could be promulgated forsubstances that have already been detectedin these streams.

It should also be noted that a recent U.S.Circuit Court of Appeals decision in the caseof Alabama Power, et al. v. EPA may result insignificant changes in the PSD regulations.The definition of baseline conditions, fugitivedust control requirements, and monitoring re-quirements are among the issues on whichthe court has rendered a decision. As a resultof the decision, EPA proposed certain revi-sions to the PSD regulations on September 5,


1979. However, the effect of the court deci-sion and the proposed regulations on the con-ditions for PSD permits for oil shale facilitiesis unclear at this time.

Policy Options

LIMITS ON DEVELOPMENT

Siting constraints will probably not besevere for an oil shale industry of 200,000 to400,000 bbl/d. However, it appears likely thata large industry (the order of 1 million bbl/d)could encounter siting difficulties because ofthe Class H status of the resource region, thepossibility that the initial facilities will ex-haust the total PSD increments over largeareas, and the existence of Class I areas nearthe region. If this appears to be the case,there are several possible actions that couldbe taken. These are briefly described below.

Retain the current regulatory structure.This option would not alter existing airquality standards and PSD regulationsas promulgated under the Clean Air Act.Under existing law, all oil shale facilitieswould have to undergo a preconstruc-tion review before a PSD permit wouldbe granted. The use of BACT would berequired, and the developer would haveto demonstrate that air quality regula-tions would not be violated either withinthe Class II area of development or innearby Class 1 areas. As indicated previ-ously, the current policy of allocatingPSD increments on a first-come, first-serve basis might constrain the commer-cialization of those technologies that arein the early phases of development, andin addition might limit the ultimate sizeof an oil shale industry within the re-source region.Coordinate issuance of PSD permits foroil shale plants. This option would notalter existing PSD regulations as promul-gated under the Clean Air Act. However,it would change the current approach tothe issuance of PSD permits for oil shaleplants by EPA. Rather than issuing PSDpermits on a first-come, first-serve basis,EPA would encourage coordination with

all prospective oil shale developers priorto their preparation of PSD applications.This effort would seek a coordinatedstrategy for maximizing shale oil produc-tion while maintaining the ambient airquality at regulated levels. Implementa-tion could be constrained by, for exam-ple, antitrust laws.Alter existing regulatory procedure in al-location of PSD increments. Under thisoption, EPA would allocate a portion ofthe total PSD increment to each firmwhen it applied for a PSD permit. The re-maining portions of each incrementwould be reserved for future industrialgrowth. Although this option wouldallow for a certain level of additionalgrowth, it could impose technical andeconomic burdens on the individual ap-plicants, because each proposed facilitywould be required to maintain loweremission levels than would be the caseunder the existing regulatory structure.Redesignation of the oil shale regionfrom a Class II to a Class III area. Thisoption would lower air quality but wouldallow for more industrial development.The action would be initiated at theState level, with final approval beingnecessary from EPA. The following cri-teria would have to be satisfied:—the Governors of Colorado, Utah, or

Wyoming must specifically approvethe redesignation after consultationwith legislative representatives, andwith final approval of local govern-ment units representing a majority ofthe residents of the area to be redesig-nated;

—the redesignation must not lead to pol-lution in excess of allowable incre-ments in any other area; and

—other procedural and substantive re-quirements for redesignation underState and Federal law must be satis-fied.While such an option would appear to

allow for about twice as much oil shaledevelopment as is presently possibleunder a Class II area designation, con-


straints would still occur because of thenearby Class I areas.Amend the Clean Air Act. This congres-sional option would exempt the oil Shaleregion from compliance with certainprovisions of the Clean Air Act. Con-gress might direct EPA and the States inquestion to redesignate the oil shale re-gion from a Class 11 area to a Class 111area, and to exempt the oil shale devel-opers from maintaining the visibility andair quality of nearby Class I areas. Thisoption would remove the major uncer-tainties surrounding the siting of oilshale facilities within the resource re-gion itself, and would remove any sitingbarriers connected with the degradationof nearby Class I areas. Such an optionwould allow development up to the ClassIII standards, which permit lower airquality than Class II standards. Thus,this option would allow an industry of upto 800,000 bbl/d to be sited in the Pice-

ance basin and an unknown amount inUtah and Wyoming, but at the cost of in-creased air pollution.

IMPROVE TECHNICAL INFORMATION

Additional analysis is needed of the poten-tial effects of oil shale development on airquality. Such analysis will be useful in identi-fying long-term R&D needs in protecting airquality and in identifying siting problems im-posed by existing air quality regulations andstandards. Some options for improving thequality of technical information might in-clude: the further development of existingR&D programs, the coordination of R&D workby Federal agencies, the redistribution offunds within agencies for air quality re-search, increased appropriations to agenciesto accelerate their air quality studies, and thepassage of new legislation specifically tied tofunding R&D relating to air quality impacts atvarious levels of oil shale development.

Water QualityIntroduction

Development and operation of oil shale fa-cilities could contaminate surface and groundwater from point sources such as cooling wa-ter discharges, nonpoint sources such as run-off and erosion, and accidental dischargessuch as spills from trucks, leaks in pipelines,or the failure of containment structures. Thepollutants could adversely affect aquaticbiota, irrigation, recreation, and drinkingwater. The severity of these impacts will bedetermined by the scale of operation, theprocessing technologies used, and the typesand efficiencies of the pollution controls.

The water systems may be affected duringthe operating lifetime of an oil shale facility,and such long-term impacts as those from theleaching of disposal piles could continue formany years after operations ceased. Accu-rate prediction of the impacts requires anunderstanding of the characteristics, trans-port routes, and fates of the pollutants that

might be released. Much work has been doneto describe the quantity and quality of sur-face and ground water resources in the oilshale region. However, little is known aboutthe nature and ultimate impacts of the pollut-ants produced by oil shale processing. For ex-ample, a number of these pollutants may becarcinogenic, mutagenic, and teratogenic.*

Information is not available on the risksposed by these pollutants at the levels likelyto be encountered in the surface and groundwater affected by oil shale development.

In this section:

. The types of wastewaters produced byoil shale operations are characterized.

● Rates for the generation of these con-taminants are estimated.

● Potential impacts of effluent streams onsurface and ground water are identified.

*(krcino~ens cause c a n c e r . Nlutagens cause mut[ltions inoffspring. ‘1’era togens cause fetal defects.


●

●

●

●

●

●

●

The quality of surface and ground waterresources in the oil shale region is exam-ined.The applicable Federal and State waterquality regulations and standards aredescribed.The effects of these regulations andstandards on a developing oil shale in-dustry are analyzed.The pollution control strategies that maybe applied are described and evaluated.The net rates at which pollutants will beemitted in treated streams are then esti-mated.Procedures for predicting and monitor-ing compliance with water quality regu-lations are discussed.Issues and R&D needs are summarized.Policy options are discussed.

Pollution Generation

The following discussion examines thetypes of effluents generated by various oilshale processes. Where data are available,the rates at which these effluents are pro-duced by different types of facilities areestimated.

Unit Operations and Effluent Streams

Mining will produce dusty air and gasesthat must be cleaned to protect the miners.Wet scrubbing of this mine ventilation air willproduce wastewater streams that will haveto be treated. If the shale deposits are locatedin ground water aquifers, then mine drainagewater will be produced that must be con-sumed, discharged to a surface stream, or re-

1 % 0 ( 0 credit OTA staff

Mine dewatering at tract C-a— water quantity has been greater than anticipated at this site


injected into the aquifers. The drainage wa-ters will contain inorganic salts, chloride andfluoride ions, and boron. They should not con-tain significant concentrations of dissolvedgases or organic chemicals, although dis-solved H2S may be found in some locations.

Retorting produces water by combustion ofhydrogen, by release of moisture present inthe feed shale, and by chemical decomposi-tion of kerogen. In some aboveground retorts(such as TOSCO 11 and Lurgi-Ruhrgas), thiswater is entrained in the retort’s gas streamand is condensed when the product gas iscooled. This “gas condensate” will be con-taminated with NH3, CO2, H2S, and volatile or-ganics, but will not contain appreciable quan-tities of inorganic salts. In other processes(such as in situ retorting or the Paraho orUnion “B” aboveground retorts) some of thewater may condense within the retort or inthe oil/gas separators. This “retort conden-sate’ will contain H2S, NH3, CO2, and dis-solved organics, plus inorganic salts thathave been leached from the shale in the re-tort, Trace elements and toxic metals couldalso be present.

Upgrading will include several operations:gas recovery, hydrogen generation, gas-oiland naphtha hydrogenation, delayed coking,NH 3/acid-gas separation, foul-water strip-ping, and sulfur recovery. Gas recovery andhydrogen generation produce little wastewa-ter. However, hydrotreaters and cokers pro-duce foul condensates that are contaminatedwith dissolved gases and organics. Gases areusually removed within the upgrading unit.Thus, the principal pollutants in the final ef-fluent stream are dissolved organic com-pounds.

Air pollution control. —Dust scrubbers andwater sprays will produce an effluent thatcontains suspended solids and dissolved in-organic salts. Effluent streams from gascleaning devices will also contain solids andsalts as well as HC, H2, NH3, phenols, organicacids and amines, and thiosulfate, and thio-cyanate ions, The principal sources of waste-water will be scrubbers and units for the re-covery of sulfur and NH3.

14 Different devices

produce significantly different quantities ofwastewater with different types and concen-trations of contaminants. For example, aClaus/Wellman Lord sulfur recovery systemwould produce a neutralized acidic wastewa-ter;15 a Stretford sulfur absorption unit wouldnot.

Steam generation and water cooling.—High-quality water must be used to generatesteam for power generation or process needs.Generally, the boiler feedwater must betreated to remove inorganic salts. The treat-ment (usually lime softening or ion exchange)generates liquid wastes. In addition, thewater in a boiler becomes concentrated indissolved materials, and a portion must becontinually replaced with freshwater. Thechemical species in the boiler wastewater(blowdown) will be similar to those in the rawwater, but they will be more concentrated.

Wet cooling towers will be used to cool thewater that is used in heat exchangers. Cool-ing towers work by evaporating a portion ofthe water passing through them. This evap-oration concentrates the chemicals that enterwith the feedwater, just as in a boiler. Thewater that must be removed to control the ac-cumulation of solids (blowdown) will be chem-ically similar to the feedwater but will alsocontain chemicals that are added to controlthe growth of algae in the tower.

Spent shale disposal. -Spent shale fromaboveground retorting will be exposed toleaching by rainfall, snowmelt, or irrigationwater. If wastes are disposed of by backfill-ing mines, they may be leached by groundwater. Leachates from various spent shaleshave been studied by a number of investi-gators. 16 17 Their properties vary widely withthe retorting process but in general they con-tain significant concentrations of total dis-solved solids (TDS), sulfate, carbonate, bicar-bonate, and other inorganic ions, and lesseramounts of trace elements and organic com-pounds. They are alkaline, with pH valuesranging from 8 to 13. Their addition to thenaturally occurring waters in the oil shale re-gion could result in significant water qualitychanges, but the severity of the risk is diffi-


cult to ascertain. For example, one leachatewas tested according to EPA procedures, andthe spent shale could not be classified as ahazardous waste on the basis of its trace ele-ments and toxicity .18 However, some spentshales could be classified as hazardous be-cause of the presence of organic residues. 19

Leaching of in situ retorts.—In situ retort-ing presents an environmental problem be-cause ground water is found in many of thedeposits to which this process could be ap-plied. The increases in permeability thatwould result from mining, fracturing, and re-torting would facilitate leaching after dewa-tering operations are discontinued. Solublematerials in the spent shale would thus enterthe ground water and would eventually reachsurface streams. Such transport would takelong periods of time. However, if aquifers arecontaminated, cleanup would be virtually im-possible.

Summary of Pollutants Produced byMajor Process Types

Approximate rates of generation of majorpollutants are summarized for four facilitiesin table 51. * Five factors should be kept inmind in reviewing this table:

●

●

●

The rates are for the generation of pol-lutants—not for their release to the en-vironment. The rate of release will be de-termined by the strategies that are usedto remove the contaminants.Retort condensates are not shown forthe AGR processes because it is as-sumed that the retorts will be operatedat temperatures that will avoid conden-sation of water vapors within the retort.This should be achievable with most re-torting systems. However, others (likethe Union “B”) may produce substantialquantities of retort condensate.No mine drainage water is shown for theaboveground plants because it is as-sumed that they will not be sited inground water areas. This assumption re-

*See app. C for details,

Table 51 .–Generation Rates for Principal Water Pollutants forProduction of 50,000 bbl/d of Shale Oil Syncrude (tons/d)a

Type of retortinq facility

Aboveground Aboveground MIS/direct indirect MIS aboveground

Gas condensatesN H3 . 75.6 147 276 189H 2 S 0.9 2 3 1 5 1.1c o2 136 17.5 541 371BOD : : 19.2 2 8 5 18,5 127

S u b t o t a l 232 63 837 574Retort condensatesN H3 (b) (b) 3,5 2.4H 2 S. . . (b) (b) – –c o2 (b) (b) 48.2 331BOD ., (b) (b) 10.1 7.3

Subtotal – — 62 43Upgrading condensatesN H3 . 134,2 1342 134,2 134,2H 2 S 58.8 58.8 58.8 58.8c o * 1,4 1 4 1 4 1.4B O D 3.7 3 7 3 7 3,7

S u b t o t a l 198 198 198 198Blowdown and waste treatmentc

C a / M g / N a d 6 0 6.3 12,2 11 2C h l o r i d e . 5.3 5 7 0 9 0.8Fluoride ., – — 0 3 0.2S u l f a t e 6.5 6.8 8.4 7 6

Subtotal 18 19 22 20Mine drainage treatmentCO3 =/ HCO3 -e (f) (f) 23,1 23,1Boron (f) (f) 0 1 0.1Ca/ Mg/Nad. (f) (f) 145 14,5C h l o r i d e (f) (f) 0.7 0.7F l u o r i d e . (f) (f) 0 5 0.5Si l ica. . , . , (f) (f) 0 5 0.5S u l f a t e (f) (f) 126 12.6

Subtotal — — 52 52

T o t a l , 488 295 1,171 887

a;ons per stream daybAssumes above-ground retorts operated a! temperatures that do not Produce condensatecln~]”de~ water pretreatment Above-ground plants use Colorado Rwer wafer MIS and MIS’

above-ground plants use mme drainage walerdGalclum magnesium and sodium Ionsecarbonale and bicarbonate IOnSfAs~umes above-ground relorflng plants are not located w ground water areas

SOURCE

●

Of ftce of Technology Assessment

fleets present developer proposals. Itwould not be valid for future plants inthe center of the Piceance basin.No retort leachates are shown for theMIS retorts because the rate of leachingand the efficacy of control systems can-not be accurately estimated. One studyestimated that a commercial MIS facilitymight yield over 2,000 ton/d of solublesalts, but only crude estimates weremade of the rate of release.20


No rates are shown for trace elements,heavy metals, or toxic organic chemicalsbecause these are produced in muchsmaller amounts than the major pollut-ants. However, they can be both morehazardous and more difficult to re-move.21-28

The estimates indicate that MIS processingon tract C-b will produce the greatest quanti-ty of wastewater contaminants for treatment,mostly because of the large gas condensatestream. A substantial difference is shown be-tween the aboveground direct and above--ground indirect plants with respect to therates at which pollutants are generated in thegas condensate streams: the directly heatedfacility produces about four times as muchdissolved gas (largely CO2 and NH3). This isbecause more air is introduced into directlyheated retorts. The trend is consistent withthe even higher gas condensate production ofthe MIS retorts, which are also assumed to bedirectly heated.

Effects of Potential Pollutants onWater Quality and Use

Salinity

Oil shale development could increase thesalinity in surface and ground water systemsthrough two processes:

Concentration of naturally occurringsaltwater as high-quality water is with-drawn for consumptive uses. (This effectis discussed in ch. 9.)Salt loading from leaching of waste dis-posal piles and in situ retorts, from re-lease of saline mine or process waters,and from ground water disturbancescaused by reinfection.

Salinity increases are a significant problembecause as water becomes more mineralized,its municipal, domestic, ecological and agri-cultural utility is reduced. * If dissolved solids

“I’his is of ma jor importance because the Colorado River sys-tem is one of the most important river systems in the South-west. I t serves :~pproxima tel~’ 15 m i]iion people. ~funicipalit ies,agrirul t u re, energv proriuc t ion. i ncfus t rv and mining, recrea-

increase over 500 mg/1, treatment for munici-pal and industrial water users becomes morecostly, and the yield of irrigated farmlandsmight be reduced. 29 For public drinking watersupplies, EPA recommends limits of 500 mg/1for dissolved solids and 250 mg/1 for bothchlorides and sulfates. 30

Oil and Grease

Because large amounts of shale oil will beproduced, processed, and transported, thereis a possibility of oilspills. If they cannot becontained or removed, detrimental impactswould occur to aquatic biota. Small spills,such as from pipeline leaks, could cause localdamage. If undetected, the long-term impactscould be substantial. Oil and grease in publicwater supplies cause an objectionable tasteand odor, and might ultimately endanger pub-lic health.

Suspended Solids

Sedimentation problems will be increasedbecause large amounts of land will be dis-turbed, which will increase the area’s sus-ceptibility to erosion. Suspended solids makesurface water cloudy and increase its tem-perature, thereby affecting aquatic life. Sus-pended solids in industrial waters can dam-age some types of equipment.

Temperature Alteration

An industry may alter stream tempera-tures by discharging warm waste streams, byconsuming cool water, or by lowering theground water table. Discharges from power-plants could also increase temperatures, butthe developers do not expect to do this. Theconstruction of new reservoirs could alsoalter stream temperatures. While tempera-ture is not a critical factor in water for in-dustrial use, for drinking, or for irrigation,

tion, wildlife, Federal lands, and Indian reservations all com-pete for its waters. PresentIV, salinity of the Colorado River atIIoover Dam is 745 mgl. Unless efficient control technologiescan be employed, estimates have indicated that a large oilshale industry has the potential, due to salt loading and saltcorwent ration, to increase the salinity level a t Hoover Dam bvseveral mg 1.

— —


large variations would affect all aquatic life,both directly and indirectly (e.g., by influenc-ing their susceptibility to disease and toxiccompounds. )3] Because the Colorado Riversystem is large, and variations in water tem-peratures occur naturally, it is not expectedthat oil shale development will significantlyaffect its temperature. 32

Nutrient Loading

The potential sources of nitrogen and phos-phorous are ground water discharge, runofffrom raw and spent shale, municipal wastes,and chemical fertilizers used for reclaimingland. These nutrients would adversely affectnearby surface waters, but the effect on thetotal river system is uncertain. The overallimpact will depend on where the facilities arelocated and on the degree of waste treatmentused.

Toxic Substances

Sources of toxic trace elements and organ-ic chemicals include stack emissions fromprocessing operations, chemicals used in up-grading and gas processing, leachates fromraw and retorted shale, and associated in-dustrial and municipal wastes. These sub-stances are of concern because of their po-tential impact on aquatic life, and on humanhealth through drinking water supplies andirrigation. Concentrations of certain mineralsin the region’s water already exceed the lim-its set for certain water uses. * Oil shale de-velopment could increase these levels andcould also add other toxic contaminants. Forexample, cadmium, arsenic, and lead, andother heavy metals could be leached fromspent shale piles. Organic compounds (phe-nols, benzene, acetone) that are suspectedcarcinogens and that have been identified byEPA as high-priority hazardous water pollut-ants also are found in oil shale processwaters.

*For example, the boron content in Eva ma lion Creek, nearlease tracts U-a and U-b exceeds the irrigation standard. Seethe next section on water quality in the oil shale region for amore detailed discussion,

Microbial Contamination

The microbial contamination of surfacewaters could occur if rapid populationgrowth overloads sewage treatment facil-ities. (See ch. 10 for a discussion of the prob-lems of rapid growth.) Improperly treatedsewage containing viruses, bacteria, andfungi could be released into the water system.These problems could be controlled by theconstruction or expansion of sewage treat-ment plants.

Water Quality in the Oil Shale Region

The current properties of the water definehow it must be treated before it can be usedin oil shale facilities. More importantly, theydefine the level to which wastewater must betreated before it can be discharged. In gener-al, regulations do not permit the discharge orreinfection of wastewater unless it is at leastas pure as the receiving stream or aquifer. Asindicated by the data in table 52, the qualityof surface streams is highly variable. It alsotends to deteriorate between upstream anddownstream reaches, as exemplified for Pice-ance Creek east and west of tract C-b. All ofthe streams described in the table satisfy thestandards promulgated by EPA and the U.S.Public Health Service for the maintenance ofaquatic life and wildlife. Moreover, with theexception of Evacuation Creek, all are suit-able for irrigation water supplies and for live-stock watering. Evacuation Creek’s boroncontent exceeds the irrigation standard, andits dissolved solids level exceeds the livestockwatering standard. However, none of thestreams satisfies the standards for publicdrinking water. The standard for dissolvedsolids is exceeded by all the streams, espe-cially Yellow Creek and Evacuation Creek.Evacuation Creek also exceeds the standardfor boron, sodium, and sulfate ions. The sodi-um standard is also exceeded by YellowCreek, and the sulfate standard by all threecreeks and the spring.

Ground water is generally of poorer qualitythan surface streams. The quality of alluvialaquifers and of the upper and lower bedrock


Table 52.–Quality of Some Surface Streams in the Oil Shale Region (mg/l)

Basin Piceance Uinta Piceance Piceance Piceance Piceance Piceance Uinta

Piceance Creek Piceance Creek Spring at EvacuationStream Colorado River White River east of C-b west of C-b Yellow Creek WIIIOW Creek Wallow Creek Creek

Reference 14 15 16 16 17 16 16 15

AmmoniaB i c a r b o n a t eBoronC a l c i u mC a r b o n a t eC h l o r i d eDissolved solidsFluorideHardnessMagnes iump HSilicaS o d i u mS u l f a t e

N Ab

1 6 8

N A

7 2

NA205734

NANA19NA7 0

153158

0 0 6

241

008872

0 242

5510 0 3

29929

8 21378

188

NA542

NA700 0

16718

1 0NA47

8 216

130170

NA601

NA79

0 014

9440.7

NA69

8 217

160300

0.1531,470

0.6423 1 9

118124

2,4302.09

541112

8 71 0 5

746550

0 1606

0.2143

0 14 0

9951 7

57653

7 913

138350

0 1540

0.6161

0 10 8

9101 4

51628

7.913

125310

0 0 6575

1. 95214

0 066

4,9480 9

1400209

7 910

9722.889

aSee reterence IISIbDala not ava(lable

SOURCE Office of Technology Assessme~t

ground water aquifers in the Piceance basinnear Federal lease tracts C-a and C-b isshown in table 53. * Water from the alluvialand upper aquifers could be used for irriga-tion, but its high dissolved solids contentcould harm many crops, Water from the low-er aquifer could be used only with very toler-ant plants on permeable soil, and that fromsome portions of the aquifer could not be usedat all because the lithium and boron concen-trations would be toxic to many plants. Ex-cept for the lower aquifer, the ground waterresources could be used for livestock, All ofthe water would be suitable for maintenanceof aquatic life and wildlife.

None of the aquifers meets drinking waterstandards. Special problems are encoun-tered with boron, which in one sample of low-er aquifer water exceeded the drinking waterstandard by a factor of 320.34 Also, the aver-age fluoride concentration in lower aquiferwater is about 28 times the drinking waterstandard. 35 Dissolved solids concentrations inthe lower aquifer range from a level thatwould satisfy drinking water standards (500mg/1) to over 40,000 mg/1, A concentration of63,000 mg/1 was reported for one sample. 36

“I’he grounci water resources of the Piceance basin are de-scribed in ch. 9. The bedrock aquifers are separated by the oilshale deposits of the !vlahogany Zone. Alluvial aquifers aregenera]ly found near the surface in valley walls and floors.

Aquifer

Table 53.–Quality of Ground Water Aquifersin the Piceance Basin (mg/l)

Alluvial Alluvial Upper LowerReferenced 17 16 16 16

Ammonia 0337Bicarbonate 573B o r o n 1 25Calcium ., 102Carbonate 11.4C h l o r i d e 17.9Dissolved solids 1,190F l u o r i d e 0367Hardness 600Magnesium 8 3 9pH 6 5Silica NASodium. 202S u l f a t e 467

aSee reference IIsl bDala not avadable

SOURCE Off Ice of Technology Assessment

N Ab

1 , 2 2 0

NA57

NA42

1,7504 6

NA80

NANA490430

NA550

NA50NA16

9601 4

NA60NANA

210320

NA9,100

NA7 4

NA690

9,40028

NA9 5

NANA

3,98080

Water Quality Regulations

Regulations for the maintenance of surfaceand ground water quality have been promul-gated under the Clean Water Act and theSafe Drinking Water Act. They are imple-mented at the Federal and State levels, to-gether with additional State standards. In thefollowing discussion, the provisions of theseActs that are of particular significance to oilshale are emphasized.

63-898 0 - 80 - 20


The Clean Water Act

The objective of the Federal Water Pollu-tion Control Act (FWPCA) is “to restore andmaintain the chemical, physical, and biologi-cal integrity of the Nation’s waters. ” In 1972,FWPCA was amended to establish a complexprogram to clean up the Nation’s waterwaysby limiting the effluents of all classes of pol-luters. These limits were to be tightened untilthe ultimate goal of no pollution dischargeinto navigable waters was achieved. The min-ing industry had difficulties meeting the re-quirements of this program. Congress re-sponded to these problems, and to the recom-mendations of the National Commission onWater Quality, by further amending the Actin 1977. The amended Act, now called the“Clean Water Act” refined FWPCA’s regula-tory scheme for point sources and empha-sized the control of toxic effluents. EPA, theArmy Corps of Engineers, and the States areresponsible for implementing and enforcingthis Act.

The goals of the Act are:●

●

●

●

the discharge of pollutants into naviga-ble waters shall be eliminated by 1985;wherever attainable, water qualitywhich provides for the propagation offish, shellfish, and wildlife and for rec-reation in and on water, shall beachieved by Ju ly 1 , 1983;discharge of toxic pollutants in toxicamounts shall be prohibited; anda major R&D effort shall be made to de-velop- the technology necessary to elimi-nate the discharge of pollutants into thenavigable waters, the waters of the con-tiguous zones, and the oceans.

To achieve these goals, emissions stand-ards are to be set to limit discharges frompoint and nonpoint sources, and ambientstandards are to be established for the quali-ty of surface waters.

Effluent standards. —Different ap-proaches are used for control of point andnonpoint sources. Point sources release a col-lected stream of pollutants through sewers,pipes, ditches, and other channels. These can

be monitored and regulated with some preci-sion, and they are suited to the application ofcontrol devices. Nonpoint sources are sitesfrom which there is uncollected runoff. Exam-ples are irrigated fields and waste disposalareas. They present regulatory and techno-logical difficulties, and as a result, they aresubject to less stringent legal controls.

FWPCA established a complex regulatoryscheme to control pollution from industrialpoint sources:

●

●

●

●

●

by July 1977, all nonmunicipal pollutersmust use the “best practicable pollutioncontrol technology currently available”(BPT); public sewage works must usesecondary treatment;by July 1983, nonmunicipal point sourcesmust use the “best available technologyeconomically achievable” (BAT), munici-pal sewage treatment plants must usethe “best practicable waste treatmenttechnology;”special effluent standards for toxic pol-lutants must be met prior to the 1977deadline;new facilities must use the “best avail-able demonstrated control technology;”andspecial restrictions, based on ambientwater quality standards, must be used ifthe national effluent standards will notmeet water quality targets in a givenbasin.

The 1977 amendments changed this frame-work: the July 1977 BPT deadline was ex-tended until April 1, 1979, for point-sourcepolluters who demonstrated a good-faith ef-fort to achieve compliance, and the BAT pro-visions were completely revised. Industrialpoint-source pollutants were divided intothree classes— toxic, conventional, and non-conventional. Each is treated differently.Toxic pollutants cause death, disease, behav-ioral abnormalities, cancer, genetic muta-tions, physiological malfunctions, or physicaldeformations in any organisms or their off-spring. Sixty-five toxic pollutants must meetthe BAT standards by July 1, 1984; othersmust meet BAT standards within 3 years


after effluent limitations are established.Conventional pollutants include biologicaloxygen-demanding substances, suspendedsolids, fecal coliform, and changes in pH.They are subject to the application of “bestconventional control technology” by July 1,1984. In general, this standard is less strin-gent than the BAT standard. Nonconvention-al pollutants— those classified as neither tox-ic nor conventional—will be subject to theBAT standards no later than July 1, 1987.

Specific limits on these effluents must beadhered to by individual polluters. In prac-tice, effluent limitations are developed byEPA for each industry. No discharge of anypollutant from a point source is allowed un-less a National Pollutant Discharge Elimi-nation System (NPDES) permit has beengranted. To obtain a permit, the polluter mustmeet the applicable effluent limitations, tech-nology standards, and water quality goals.Permits are obtained from EPA or from the in-dividual States, if they have taken over theregulatory role. Cancellation of permits fornoncompliance is one method of enforcing theAct, because without a permit, many industri-al operations cannot be carried out. It shouldbe noted that permits do not simply recapitu-late the effluent guidelines; additional ambi-ent standards may also be imposed.

Special attention is given to new sourcesand to sources that discharge into publiclyowned treatment works. In practice, perform-ance standards for new sources are oftenequivalent to the 1983 BAT limitations devel-oped for existing industries. Any new sourcethat complies with an applicable standard ofperformance is not to be subjected to morestringent standards during the first 10 yearsof operation.

Expected effluent limitations for oil shalefacilities.—EPA has not yet developed stand-ards of performance for oil shale facilities.However, standards have been establishedfor petroleum refining, which has severalsimilarities. The BPT standards shown for pe-troleum refining in table 54 were based on

Table 54.–Effluent Limitations for Petroleum Refineries UsingBest Practicable Pollution Control Technology (BPT)

(pounds per 1,000 bbl of feedstock)

Average of daily valuesMaximum for for 30 consecutive

Effluent characteristic any 1 day days shall not exceed

Biochemical oxygen demand( B O D 5 ) 192 102

Total suspended solids 132 8 4Chemical oxygen demand 136 70011 and grease 6 0 3 2Phenolic compounds 0 1 4 0068Ammonia as N 8 3 3 8S u l f i d e 0124 0056Total chromium O 29 0 1 7Hexavalent chromium 0025 0011p H Must be within the range of 6.0 to 90

SOURCE E R Bales and T L Thoem feds j Pololoo Coflrro GUAInI-e lo, 0 .Wk Lle~eoomenl Append/x Envlro!lfnenldl Protect Ion Agency Cinclnnaft Ohio July 1979 0 D 9

the following wastewater management proce-dures:

●

●

sour water stripping to reduce NH3 andH2S;segregation of sewers;no discharge of polluted cooling water;andoil, solids, and carbonaceous wastes re-moved just prior to discharge.

The BAT standards illustrated in table 55were defined using additional treatment

Table 55.–Effluent Limitations for Best Available TechnologyAchievable (BAT) for Petroleum Refinery Facilities

(pounds per 1,000 bbl of feedstock)

Effluent Iimitations



Biochemical oxygen demand(BOD 5 ) . 32 2.6

Tota l suspended so l ids. 3.0 2 6C h e m i c a l o x y g e n d e m a n d 168 1340 1 1 a n d g r e a s e 0 6 0 0.48P h e n o l i c c o m p o u n d s 0015 0010Ammonia as N. 20 1 5S u l f i d e . 0066 0042T o t a l c h r o m i u m 0 1 5 0.13H e x a v a l e n t c h r o m i u m , 0.0033 0.0021p H Must be within the range of 6.0 to 9.0

SOURCE E R Bales and T L Thoem {eds I f%luton Coofro/ Gwddnce Pm 0// 5?M/e Deve/op-rnenf Appendix Enwronmental Protect(on Agency Cincinnati Ohio July 1979 pc1 11

300 An Assessment o/Oil Shale Technologies

methods now practiced by some petroleumrefineries. These methods include:

●

●

●

●

●

●

●

●

use of air cooling rather than wet coolingtowers;reuse of sour water stripper wastes;reuse of cooling water in the watertreatment plant;using treated wastewater as coolantwater, scrubber water, and in the watertreatment plant;reuse of boiler blowdown as boiler feed-water;use of closed cooling water systems,compressors, and pumps;use of rain runoff as cooling tower make-up or water treatment plant feed; andrecycling of untreated wastewaterswherever practical.

NSPS for petroleum refineries, based on acombination of BPT and BAT standards, areshown in table 56. New sources must meetdischarge standards that reflect the greatestdegree of effluent reduction which the EPAAdministrator determines to be achievablethrough application of the best available dem-onstrated control technology, process altera-tions, or other methods including, wherepracticable, zero discharge systems.

Federal ambient water quality stand-ards. —The Water Quality Act of 1965 re-quired the States to adopt ambient standards

Table 56.–New Source Performance Standards for PetroleumRefineries (pounds per 1,000 bbl of feedstock)

Effluent Imitations



Biochemical oxygen demand( B O D5 ) 1 4 7 7.8

T o t a l s u s p e n d e d s o l i d s . 9.9 6.3Chemical oxygen demand ~ ~ 104 540 1 1 a n d g r e a s e 4.5 2.4Phenolic compounds 0.105 0.051A m m o n i a a s N 8.3 3.8S u l f i d e 0093 0042T o t a l c h r o m i u m . , 0220 0.13H e x a v a l e n t c h r o m i u m . 0.019 0.0084pH ., Must be within the range of 60 to 90

SOURCE E R Bales and T L Thoem (eds I Po//uOofl CofMro/ Gwdance for Od Sha/e L7eve/opmenl Append/x Environmental Protection Agency Clnclnnatl Oh[o July 197[1 p012

for interstate waters. FWPCA required Statestandards for intrastate waters as well. EPAwill develop the standards if a State fails todo SO.

The ambient standards are the basis forpreventing the degradation of presently cleanwaterways. The regulations provide, withoutqualification, that “No further water qualitydegradation which would interfere with orbecome injurious to existing instream wateruses is allowable. ” Thus, if a stream is suit-able for the propagation of wildlife; for swim-ming; or for drinking water, then it must re-main suitable for these uses. Because smallincreases in pollutant loads may not be incon-sistent with protecting a possible present use,the States are allowed to decide whether “toallow lower water quality as a result ofnecessary and justifiable economic or socialdevelopment. ” Such decisions cannot be ap-plied to waters that constitute an outstandingnational resource (e.g., national parks, wil-derness areas), and they cannot allow waterquality to fall below the levels needed to pro-tect fish, wildlife, and recreation.

Before a State can issue a discharge per-mit it must have a program for reviewing andrevising its water quality standards. EPA es-tablished the following guidelines for Statereview and revision:

● standards must be reviewed every 3years and revised where appropriate;

● standards must protect the public healthand welfare, and not interfere withdownstream water quality standards;

existing standards must be upgradedwhere current water quality could sup-port higher uses than those presentlydesignated;

● existing standards must be upgraded toachieve FWPCA’s 1983 goal of fishableand swimmable waters, where attain-able. Attainability is to be determined byenvironmental, technological, social, ec-onomic, and institutional factors; and

● existing water quality can degrade inonly specific instances, for example, ifexisting standards are not attainable


because of natural conditions such asleaching.

Once an ambient standard is established, aState must identify stream reaches for whichthe 1977 effluent limitations are not suffi-ciently stringent. For such areas, the Statemust determine the total maximum pollutantloads that will allow the ambient standard tobe met, This information is used to set morestringent effluent standards.

Current State standards for Colorado andUtah. —In Colorado, streams may be assignedto one of four categories. Drainage from leasetracts C-a and C-b would discharge to the por-tion of the White River from the mouth of thePiceance Creek to the Colorado/Utah Stateline. This area is in Colorado’s water cate-gory B2. These waters are suitable, or are tobecome suitable, for customary raw waterpurposes (e.g., irrigation, livestock watering)except for primary contact recreation, * Thewater quality criteria for category B2 arelisted in table 57. Colorado also has an anti-degradation policy applicable to all streams.

Utah has 11 stream classifications, Twostreams in and around oil shale tracts U-aand U-b, Evacuation Creek, and the WhiteRiver, are classified as CW (i.e., warm waterfisheries). Their waters are suitable for all

*Prim:~rV ronttirl rerrc:)tifjn includes sw imrnin~, water ski-ing. and diving.

Table 57.–Colorado Water QualityStandards for Stream Classification B2

Parameter Criteria for B2 streams

Settleable solids floating solids Free fromtaste, odor, color and toxicmaterials

Oil and grease Cannot cause a film or otherdiscoloration

Radioactive material Drinking water standardsFecal conform bacteria Geometric mean less than 1,000

units per 100 millilitersTurbidity Cannot increase more than 10

unitspH 60 to 90Temperature Maximum 900 F

Change Streams 50 FLakes 30 F

SOURCE E R Bates and T L Thoem (eds I Po/JufIorI ConfroI Go(dance for 01/ Sbd/e De,e)oprnenl Append/x E n v i r o n m e n t a l Prolecl(on A g e n c j Clnc(nnatl Ohio JuIy 1979 pD 20

raw water uses (except contact recreation)without treatment, but with coagulation, sedi-mentation, filtration, and disinfection prior touse as domestic water supply. Temperaturelimitations are also imposed. The water quali-ty criteria for class CW are shown in table58. In addition, Utah, like Colorado, has anantidegradation policy.

Table 58.–Utah Water Quality Standardsfor Stream Classification CW

Parameters Criteria for CW streams

Radioactive and chemical Drinklng water standardsSettleable solids. 011, floating solids, Free from

taste, odor, color, and toxicmaterials, turbidity, etc

Total coliform bacteria Less than 5,000 units per 100milliliters

Fecal conform bacteria Less than 2,000 units per 100milliliters

pH 65 to 85, no Increase >0.5Biochemical oxygen demand (BOD5) Less than 5 milligrams per IiterDissolved oxygen >6.0milligrams per literTemperature Maximum 680 F

S O U R C E E R B a t e s and T L Thoem (eds I Polluf(on ComroI Gufdafice to{ Oh Shd,e Oeve/ojment Appendtx Enwronmental P r o fecllon Aqenc~ Clncnnaf O h i o JIJY 1979 p021

Proposed State standards.—FWPCA re-quired the States to designate areawide pol-lution control planning agencies. The Colora-do West Area Council of Governments andthe Uinta Basin Council of Governments havebeen designated for the oil shale region.These agencies are to plan, promulgate, andimplement a program designed to protect sur-face water quality. Stream classificationsand water quality standards are to be devel-oped. The multiple-use classifications pro-posed for streams, which may supersede ex-isting classifications previously discussed, in-clude:

●

●

●

●

The

Class I—aquatic life, water supply,recreation, and agriculture:Class II—water supply, recreation, andagriculture;Class III—recreation and agriculture;andClass IV—agriculture.

respective water quality criteria areshown in table 59. The classifications and thequality criteria will apply to all streams in theoil shale region.


Table 59.–Proposed Water Quality Criteria for Designated Uses

Parameter Water supply Aquatic life/ wildlife Recreation Irrigation Livestock

Alkalinity as CaCO 3 ., ., . –Aluminum-total . . . . . . . . . –A l u m i n u m - d i s s o l v e d . . . . , –Total ammonia as N, ., ., ., ., 0.5 mg/la

Unionized ammonia as N . –Arsenic-total ., ., 0.01 mg/lB a r i u m - t o t a l , . 1,0 mg/lBeryllium-total ., ... –Boron ., ., . . ~ ~ ~ ., 1.0 mg/la

Cadmium-to ta l . . . . , . , . , ,0 ,01 mg/ lC h l o r i d e - t o t a l . 250 mg/lChromium-total . . . 005 mg/lFecal coliform ., ., 2,000/100 ml f

Color, ., ... ., ., .75 color unitsa

Copper-total. . ., ., .1.0 mg/lCyanide. . . . . ., . ., .020 mg/lHardness ., ., ., ., ., –Iron-total. ., ., . –Iron-dissolved ., ... ..03 mg/lL e a d - t o t a l . , 0.05 mg/lManganese-total . . ... .0,05 mg/lM a n g a n e s e - d i s s o l v e d . , 0 , 0 5 m g / lM e r c u r y - t o t a l . . , . . . . . . 0 , 0 0 2 m g / lMolybdenum-total —Nickel-total ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ –N i t r a t e - t l , 10 mg/lDissolved oxygen .. ~ ~ ~ ~ ~ ~ ~ ~ 40 mg/l f

pH . . . . . .. 5.0-9.0P h e n o l s ~ ~ 0.001 mg/lTotal PO4-P ., ~ ~ ~ ~ ., –Phthalate esters –PCB ., ., –Selenium-total ., . 0.01 mg/lS i l v e r - t o t a l . . , . , . . 0.05 mg/lSilver-dissolved –Sodium ., ., ~ ~ .270 mg/la h

Sulfate-total. ., . ., ., ., 250 mg/lTDS ., ., 500 mg/la

TSS ... ., ., ., –H 2S (undissociated) ., ., ., 0.05 mg/lTemperature . ... ... ., –Zinc-total. ... . 5.0 mg/l

30-130 m g / la

0.1 mg/l0.1 mg/la

—0,02 mg/l0.05 mg/l—1,1 mg/l—0.003 mg/l—0.3 mg/l f

2,000/100 mla

—

0.030 mg/l0.005 mg/l—1.0 mg/l0.3 mg/la

0.03 mg/l1,0 mg/l—0,00005 mg/l—0.1 mg/l—5.0-6.0 mg/l min.6.5-9.00.001 mg/l0.025 mg/l - Iakesa

0.003 mg/l0.000001 mg/l0.05 mg/l0,0001-0,0025 mg/lg

0.0001 mg/l———25 mg/l-medianj

0.002 mg/l(k)0.03 mg/l

—.——————————200/100 ml—————————————2,0 mg/l min.6.5-9.0——————————————

5.0 mg/lb, 20.0 mg/la C

——0.1 mg/l

0.1 mg/lb, 0.5 mg/lC d

0,75 mg/le

O.O1 b, 0.05 mg/lC

0.1 mg/lb, 1.0 mg/lC d1 ,000/100 ml

0.2 mg/l b, 5.0 mg/lC

0.2 mg/l—5 mg/lb, 20 mg/la C

—5 mg/lb, 10 mg/lC f0.2 mg/lb, 10 mg/lC d

0.01 mg/lb, 0.05 mg/lC

0.1 mg/l f

100 mg/l2.0 mg/l4.5-9.0 a

———

—(1)

2,0 mg/l

Unless otherwise mdtcaled the recommended cr!tena correspond with proposed State standardsaCWA 208 recommendation only (no proposed State standard)bCon11nuou5 Irrlgatlon, atl sods (match WOCC proPosed State standards)cshofl.~erm {rrlgatlon, neutral to alkaline fme Iexlured soilsdFor agrlcultura[ uses the WOCC except In a few Instances dld not dlshngulsh between lrrl9a-

tion and hvestock uses The CWA 208 attempted 10 distinguish the differences Therefore, underhvestock there are numerous differences between 208 and WOCC numbers Under Irrlgatlon Thelower recommended crlterla match Wf3CC numbers

eLong.term Irrlgatlon on sensltwe cropsfDlffers from proposed State standardsgLlmitlng concentration dependent on hardness

—5.0 mg/la———0.2 mg/ld——5.0 mg/ld0.05 mg/ld—0.1 mgll1 ,000/100 ml—0.5 mg/ld0.2 mg/1———0.1 mg/1——0.00005 mg/la0.5 mg/1—NO, + NO, 100 mg/12.0 mg/1—————O 5 mg/1

——3,000 mg/la—

—25 mg/ld

hMaxlmum concentration for a moderately restricted sodwm dietIwaler from which no detrimental effects WIII usually be nohced 500 mg/1Water which can have detrimental effects on sensdwe crops 500-1000 mg/1Waler that may have adverse effects on many crops and requires careful management

prachces f ,000-2000 mg/1Water fhat can be used for folerant plants on permeable SOIIS wlfh careful management

prachces 2,000-5000 mg/1IValue represents maxtmum Increase In amblenf concentraflon due 10 dischargekC,old water maximum IS 200 C, warm water maximum IS 30° C, and both Categories hmlt temper-

ature changes to 3° C

SOURCE E R Bates and T L Thoem (eds I Po//uf/orI Cmrfro/ Gu/darrce for 01/ Sfra/e Oeve/oprrrerrl Append/x, Enwronmental Protection Agency, Clncmnal{, Ohio. July 1979 pp D-29-D-30

The Safe Drinking Water Act of 1974 gram for ground water protection. It is ad-ministered by EPA and by the States.

This Act protects drinking water systemsthrough primary and secondary ambient The primary standards are intended tostandards, monitoring programs, and a pro- protect health to the extent feasible, given the


restraints of existing treatment techniquesand their costs. Interim standards were is-sued by EPA during 1975 and 1976 and wereput into effect in June 1977 (see table 60).These standards established both maximumcontaminant levels and monitoring require-ments for 10 inorganic and 6 organic chemi-cals, radionuclides, microbiological contami-nants, and turbidity. A study by the NationalAcademy of Sciences of the health effects ofdrinking water contaminants is to be the basisfor revised primary standards. The study wascompleted in June 1977, but the revisedstandards have not yet been issued.

Secondary standards, published in 1977,deal with contaminants that affect the odorand appearance of water but do not directlyaffect health (see table 61). They are not fed-erally enforceable and are only guidelines tothe States. The States may include monitoringrequirements in their laws and regulations.

Table 60,–Primary Drinking Water Standards (mg/l)

Maximum concentration

Inorganic chemicals (except fluoride)A r s e n i cB a r i u mC a d m i u mC h r o m i u mL e a dM e r c u r yN i t r a t e ( a s N ) ,S e l e n l u mS i l v e r . . ,Fluoride(degrees Fahrenheit)5 3 7 a n d b e l o w53.8to 583 .,5 8 4 t o 6 3 . 863.9 to 70,670.7 to 7927 9 3 t o 9 0 . 5C h l o r i n a t e d h y d r o c a r b o n sE n d r l nL i n d a n eM e t h o x y c h l o rT o x a p h e n eChlorophenoxys2, 4-D (2, 4-dichlorophenoxyacetic acid).2, 4, 5-TP (Silvex)

0 0 51 00010 0 50 0 50002

1000010 0 5

2 42 22 01.81 61 4

0.00020.0040.10.005

0.10.01

SOURCE E R Bates and T L Thoem (eds ) Po//u1/on Comrol Gwdaoce for 011 Shale Developmenf Append/x Enwronmental Protecllon Agency Clnclnnall Ohio July 1979 pp D-32-D-33

Table 61 .–Proposed Secondary Drinking Water Regulations

Pollutant Proposed level Principal effects

C h l o r i d e 250 mg/l TasteColor 15 color units AppearanceCopper 1 mg/l Taste, fixture stainingCorrosivity (Noncorrosive) Deterioration of pipes, unwanted

metals in drinking waterFoaming agents O 5 mg/l Foaming, adverse appearanceHydrogen sulfide O 05 mg/l Taste, brown stains on laundry

and fixturesM a n g a n e s e . 0 0 5 m g / l Taste, brown stains, black

precipitatesO d o r 3 threshold Odor

odor numberpH ., .. 65-8.5 mg/l Corrosion below 65. incrusta-

tions, bitter taste, loweredgermicidal activity of chlorineover 8.5

Sulfate 250 mg/l Taste, Iaxative effectsTotal dissolved

s o l i d s 500 mg/l Taste, reduction in Iife of hot waterheaters, precipitation in cookingutensils

Z i n c 5 mg/l Taste

SOURCE E R Bales and T L Thoem teds I Po//ufIorI Conlrol Gwdance for 0/1 S/We Uevekmrr?er?f Append/x Enwronmen[al Protect Ion Agency Clnclnnafl Ohio July 1979 0D 33

Ground Water Quality Standards

Federal.—The Safe Drinking Water Actapplies to deep-well injection of waste intoaquifers with less than 10,000 mg/l TDS thatare, or could become, sources of public drink-ing water. Seepage from pits, ponds, and la-goons is not regulated at this time.

Colorado. -No specific standards havebeen promulgated for ground water quality.However, the basic standards applicable toall other State waters do apply. Regulationsare being developed that will limit the dis-charge or injection of some contaminants.Permits are now required for injection wells,and they will be required in the future forwastewater disposal in pits, ponds, and la-goons if there is a possibility of discharge to aground water system.

Utah.—Utah also has no special standardsfor ground water. However, ground water isconsidered part of the State waters, so gener-al water quality standards do apply. Dis-charges to sources of potable water must notcause the water quality to exceed drinkingwater standards.

304 ● An Assessment of 0il Shale Technologies

Implications of Water Pollution Control Standardsand Regulations for Oil Shale Development

As indicated above, the primary objectiveof the Clean Water Act is to eliminate thedischarge of pollutants into navigable watersby the late 1980’s. In order to accomplish thisobjective all potential polluters, including oilshale developers, will be required to applyBAT, BPT, and NSPS. Point source dischargeis well-regulated under the Act, and it is ex-pected that oil shale developers would complywith the stipulations promulgated in regardto NPDES. As will be discussed in the follow-ing section, the pollution control technologiesthat are being applied to oil shale wastewatereffluents are designed for zero discharge.However, in some instances (e.g., excess wa-ter from mine dewatering) it will need to bedischarged back into surface waters or rein-fected into underground aquifers. In thiscase, water will have to be treated to meetthe standards stipulated under the NPDESpermit system or by the Safe Drinking WaterAct for reinfection—that is surface andground water quality criteria and water useclassifications will have to be maintained asstipulated by the States and EPA. In addition,it is expected that oil shale facilities will haveto meet NSPS comparable to those developedfor petroleum refining facilities.

Technologies for Control of Oil ShaleWater Pollution

Treatment of Point Sources*

Contaminants may be removed from waste-water by physical, chemical, or biologicalmeans. For complex wastes, a series of de-vices using each of these principles will benecessary.

Physical treatment devices apply gravity,electrical charge, and other physical forcesto contaminants to remove them from waste-water. Typical operations are gravity separa-tion, air flotation, clarification, filtration,stripping, adsorption, distillation, reverse os-

*De!ails of the various technologies are described in app. D.

mosis, electrodialysis, thickening, and evap-oration.

Chemical treatment devices use chemicalproperties or chemical reactions to removecontaminants. Such systems can destroy haz-ardous substances that are not amenable toconventional physical and biological systems.For oil shale wastewaters, the most impor-tant devices are those that could oxidize or-ganic compounds or reduce salt concentra-tions. Included are ion exchange, wet air oxi-dation, photolytic oxidation, electrolytic oxi-dation, and direct chemical oxidation.

Biological treatment devices contact awaste with a population of micro-organismsthat digest its organic contaminants. By con-trolling the size of the population, and by ad-justing oxygen and nutrient levels and equal-izing the conditions of the entering stream, itis possible to develop and acclimate micro-or-ganisms that can nearly eliminate many haz-ardous organic compounds. Biological treat-ment systems can be divided into two groups:

● aerobic processes (such as activatedsludge, trickling filters, rotating biologi-cal contractors, aerated lagoons, com-porting, and stabilization ponds) inwhich the population is maintained un-der oxygen-rich conditions and the or-ganic compounds are decomposed to CO2

and water; and● anaerobic processes (such as digestion)

in which oxygen levels are relatively lowand the organic compounds are de-graded to CO and methane gas.

Treatment systems. —Most devices can re-move some but not all contaminants. In atreatment system, different wastewaters aresent to different devices, each of which re-moves a specific type of pollutant, The rela-tionships among contaminants, the streams inwhich they are likely to occur, and the treat-ment processes of choice are shown in table62. Although all contaminants may be foundin nearly all streams, the streams associatedwith each contaminant have been limited tothose in which concentrations will be high


Table 62.–The Types of Contaminants in Oil Shale WastewaterStreams and Some Potential Processes for Removing Them

Contaminant Stream . . ,Potential process

Suspended solids Mine drainageRetort condensateCooling tower blowdown

Oil and grease Retort condensateGas condensateCoking condensate

Dissolved gases Retort condensateGas condensateCoking condensate

Dissolved inorganics Mine drainage

Dissolved organics

Trace elements andmetals

Trace organics

TOXiCS

Sanitary wastes

Retort condensateGas condensateCooling tower blowdownIon exchange regenerantsRetort condensateGas condensateCoking condensateHydrotreating condensate

Retort condensateGas condensate

Retort condensateGas condensateUpgrading condensateRetort condensateGas condensateUpgrading condensateDomestic service

ClarificationFiltration

Gravity separationEmulsion breaking

Steam stripping

Chemical oxidationIon exchangeReverse osmosisAdsorptionEvaporationSolvent extractionAdsorptionBiological oxidationUltrafiltrationReverse osmosisWet air oxidationChemical oxidationIon exchangeAdsorptionUltrafiltrationReverse osmosisAdsorptionChemical oxidationIncineration

Biological treatment

SOURCE R F Probsleln H Gold and R E Hicks Wafer Reauwernertfs Po/kJ//on Effects andCosts of Wafer Supp/y and Trealrnen( for the 0// Sha/e /ndusfry prepared for OTA byWater Purlflcatlon Associates October 1979

enough to require removal prior to dischargeor reuse. 37 38

Many of the devices listed in table 62 havebeen tested individually on oil shale wastewa-ters and have been found to provide some de-gree of control. 39-50 Of great importance is theperformance of these units when combined toform a “treatment train” for a specificwastewater. A separate train—consisting ofseveral individual treatment devices inseries—will be needed for each stream be-cause, in general, each will contain differenttypes of contaminants, Each contaminant willrequire a different type of removal process.For example, retort condensates may containsuspended solids, oil and grease, dissolvedgases, organics, inorganic, and trace ele-

ments. Mine drainage water may contain onlydissolved solids.

The removal efficiencies, reliabilities,adaptabilities, and relative costs of somepoint source control devices are summarizedin table 63. This information comes almost en-tirely from experience in other industries.Few of the technologies have been tested withoil shale wastewaters, and none has beentested in the complex treatment trains thatwill be necessary to deal with the wastes thatwill be encountered in commercial-scale oilshale plants. The degree of adaptability ofeach technology is particularly importantbecause it indicates the likelihood that thetechnique will transfer without difficulty tothe oil shale situation.

Most suitable technologies.—The follow-ing technologies appear most suitable:

●

●

●

●

●

●

for oil and grease: dissolved air flotationor coalescing filters;for dissolved gases: air or steam strip-ping;for dissolved organics: rotating biologi-cal contractors or trickling filters forfirst-stage removal, carbon adsorption,or wet air oxidation for polishing;for suspended solids: pressure or multi-media filtration;for dissolved solids: reverse osmosis forfirst-stage removal, clarification for sec-ond-stage, and ion exchange for polish-ing; andfor sludges: filtration and evaporation.

Costs.—Control costs depend on the oper-ating characteristics of the oil shale facilityand on the treatment methods selected. Theonly published cost estimates were preparedfor the Department of Energy (DOE). Theseestimates, upgraded for OTA to include thecost of treating excess mine drainage water,appear in table 64. Total treatment cos tsrange from about $0,25 to $1 .25/bbl of shaleoil syncrude. The low estimate applies t oaboveground retorting plants; the high to MISfacilities in ground water areas. Althoughsizable, the control costs should not them-selves preclude profitable operations.


Table 63.–Relative Rankings of the Water Treatment Methods

Contaminant Technology Removal efficiency, % Relative reliability Relative adaptability Relative cost

011 and grease Dissolved air flotationCoalescing filterClarification

909980

Very highHighVery high

Very highHighVery high

MediumMediumHigh

Dissolved gases Air strippingSteam strippingFlue gas strippingBiological oxidation

809595

High

HighVery highHighMedium

HighHighMediumMedium

MediumMediumMediumLow

Dissolved organics Activated sludgeTrickling filterAerated lagoonRotating contactorAnaerobic digestionWet air oxidationPhotolytic oxidationCarbon adsorptionChemical oxidationElectrolytic oxidation

95 BOD/40 COD85 BOD80 BOD

90 BOD/20-50 COD60-95 BOD

64 BOD/74 COD99 BOD99 BOD

90 BOD/90 COD95 BOD/61 COD

HighHighMediumHighHighMediumMediumMediumVery highMedium

MediumMediumMediumMediumMediumHighVery highHighVery highVery high

LowLowLowLowMediumVery highVery highMediumHighHigh

Suspended solids ClarificationPressure filtrationMultimedia filtration

509595

HighHighVery high

HighHighHigh

MediumMediumLow

Dissolved solids ClarificationDistillationReverse osmosisIon exchangeElectrodialysis

Low except for metals99

6 0 - 9 5High

1 0 - 4 0

HighMediumMediumHighMedium

MediumLowMediumLowMedium

MediumVery highMediumHighVery high

Sludges ThickeningAnaerobic digestionVacuum filtrationSludge drying bedsEvaporation basinsFilter pressAerobic digestion

Product 6-8% solidsLow

Product 20-35% solidsProduct 90% solidsProduct 95% solidsProduct 35% solids

Low

Very highHighHighMediumVery highVery highLow

HighMediumHighLowLowHighLow

MediumMediumHighMediumLowHighHigh

SOURCE Adapted from 4ssessrnerU of 0// Sfra/e Rerorf Wasfewa(er Trealrneru and ConVo~ Tec/rno/ogy, Hamllfon Standard Owlslon of Uruled Technologies July 1978 pp 2-12 to 2-24

Table 64.–Estimated Costs of Water Pollution Control inOil Shale Plants ($/bbl of shale oil syncrude)a

torts. For an aboveground retorting facility,the leaching problem may be reduced by dis-posal of the solid wastes in canyons, and cap-turing and treating any leachate that does oc-cur. (See figure 61. ) It is hoped that themoistened and compacted spent shale will beimpermeable to the flow of water. The top ofthe pile will be covered with topsoil o ranother growth medium that will be perme-able but that will not contain substantialquantities of soluble contaminants. A n yleachates that reach the catchment basinwould be treated. This method may be effec-tive during the lifetime of the facility.

Above- Above--ground ground MIS/

Wastewater stream direct indirect MIS aboveground

Gas condensate $0.11 $0.13 $0.45 $0.31R e t o r t c o n d e n s a t e – — 0.13 0.09Upgrading

c o n d e n s a t e 0,12 0.12 0 1 2 0.12Excess mine

drainage ., . – — 0-0.55 0-0.55

Total . . ., $0.23 $0.25 $0.70-1.25 $0.52-1.07aplants produce 50,1NI btjltd Of syncrude Aboveground plants are assumed to be not located Inground water areas Cost estimates include operating expenditures and capital amorhzatlonThey also include nonwastewater costs such as botler feedwater treatment costs

SOURCE R F Probste!n, H Gold and R E Hicks, Wafer Requwernerrk, Po//u(/on Effecls andCosk O( Waler Supp/y and rreatrnerrl for the 00 Sha/e /ndus/ry, prepared for OTA byWaler Purlflcatlon Associates, October 1979

Tests of these control strategies have notsimulated conditions of commercial-scale dis-posal piles, and past research investigationsare limited in their applicability. Questionspersist concerning shale pile permeability,

Control of Nonpoint Sources

The major potential nonpoint sources areleachates from aboveground storage of rawor spent shale and from abandoned in situ re-


Figure 61 .—An Aboveground Spent ShaleDisposal Area

~~

‘ + \

\’ --

1

Processed Shale =

-— Disposal Pile \ ’

Leachate D i t c h - - $

;

q%

+

// . , ,\

\ \

D r a i n a g e D!tch , \ \

/ ’

‘ /

‘ /‘ / //;

/.— - /‘ /,$? //’.

/;:::~&4/////7T~

y{//)’)’y”?-#

Leachate Ditch

// / /’

/ //

///)/ ,/ / Q

-—— Leachate Catch Basin

.:”&/— Retent ion Dam

—-

:&b---–– \ (ill\ \

\ , Emergency Spillway

‘\ \ ‘~.\ / ‘\

‘ \ \ \ \

SOURCE: Surface Mining of Non-Coal Minerals, National Academy ofSciences, Washington, D C., 1979, p. 126,

erosion potential, reclamation effectiveness,and the balance between erosion and soil pro-duction rates. Water and leachates may per-colate into underlying alluvial aquifers. *These effects need careful monitoring atpioneer commercial facilities.

The efficacies of these control strategiesafter site abandonment are even less certain.Long-term monitoring and custodial care maybe required to assure that contaminants arenot released from the catchment basin as aresult of dam failure or extraordinarily heavyrainfall or snowfall,

For in situ processing, laboratory experi-ments indicate that high temperatures con-vert soluble solids in spent shale into insolu-ble mineral complexes. If such temperaturescould be achieved in commercial-scale oper-

*rI’here are other techniques as well, For example, preleach-ing of spent shale, capillarv brakes, and covering spent shalewith open pit overburden, See the section on land reclamationin this rhapter for more detail.

ations, they might serve as a primary methodfor reducing leaching. Several uncertaintiesprevent assessing the feasibility of this ap-proach. For example, the mineral complexesproduced in the field would have to remain in-soluble for long periods of time even if theretorts were backflooded. Also, to eliminateleaching, all of the spent shale in the retortswould have to be insoluble. Because controlof MIS retorting is difficult, portions of theretorts may not become hot enough to pro-duce the insoluble complexes. Control of re-torting temperatures in TIS processing iseven less certain. Since there would be mas-sive amounts of waste, increased percolationby ground water, and thus greater leachingpotential, these uncertainties may mandatethe adoption of retort abandonment strate-gies.

Retorted shale can form a cement-like ma-terial if it is properly prepared, and waterslurries of finely crushed retorted shale couldbe injected into burned-out retorts to fill voidareas and to make the spent shale imper-meable to water flow. To prevent leaching,the cement formed from the injected slurrywould have to have very low permeability;otherwise, the cement itself might produce atroublesome leachate, thereby compoundingground water pollution, Distributing the slur-ry uniformly within the retort may also provedifficult.

Another approach would be to pump fresh-water through the retort to intentionallyleach out the soluble components. The leach-ates could be treated and then reinfected on adowngradient from the retorts. It is possiblethat leaching could be accelerated in thisway, but the process might be costly and time-consuming and the technology has yet to bedeveloped.

“Hydrologic barriers” might be used toprevent or control the flow of water into theretort area, thereby preventing the disper-sion of leachates. One possibility is drilling acontinuous series of holes around the retortarea and filling them with a cementitiousslurry. By itself, this technique may not be ful-ly effective since the retorts may be in aqui-


fers in which water moves vertically. The ef-fectiveness could be increased by cementing(grouting) the retorts to seal their more per-meable zones and fractures.

Another possibility would be to divert amajor port ion of the ground water f lowaround the retort area. In this “hydraulic by-pass” option, artificial channels or barrierswould capture most of the ground water flow-ing toward the retort area, direct it aroundthe area, and then return it to the ground wa-ter system.

Ultimate Disposition of Wastewater

At present, no developer plans to dischargewastewaters to surface streams; rather, thefinal wastes will be disposed of by recycling,evaporation, and reinfection. In the future,consideration may be given to treating anddischarging all surplus process waters. Thiswould be much more expensive than treat-ment to industrial standards, but it would re-duce the impacts of development by augment-ing stream flows in a water-short region. Ifthis option is adopted, water treatment needswill increase significantly and highly efficienttreatment methods will be necessary.

Recycling

Present developer plans call for treatingand recycling wastewaters whenever practi-cal. This depends only on the ability of wastetreatment systems to purify the wastewatersso that they could be reused in other portionsof the process. Nearly all of the wastewaterscould be reused after appropriate treatmentfor cooling tower makeup, for dust control,for shale disposal, for leaching, for revegeta-tion, and for generating steam that could beinjected into either aboveground or in situ re-torts. As discussed previously, efficient, reli-able, adaptable, and cost-effective methodsappear to be available for the major contami-nated streams. Their capability of treatingthe wastes to discharge or reinfection stand-ards is not relevant as long as the streams areto be recycled.

Treated cooling tower wastewater couldbe reused after dilution with other treatedstreams. Treated gas condensates are alsosuitable for cooling water because theyshould have low concentrations of inorganiccontaminants and volatile organics. Retortcondensates could also be used after theirdissolved substances are removed.

Water quality criteria have not been estab-lished for dust control, shale disposal, orrevegetation, but water similar to river waterwould probably be acceptable. It should bepossible and practical to treat gas conden-sates to this level. Treated retort condensatesshould also be acceptable, although success-ful treatment has yet to be demonstrated.Steam raising, for example, with the thermalsludge system, is at present a more reliableoption. These condensates (either treated oruntreated) could also be used as a slurrymedium for grouting in situ retorts. Testswould be needed to determine if the waste-water contaminants were truly immobilizedso that they could not be leached by groundwater.

Evaporation

Most of the wastewaters will be disposedof in dust control and in the waste disposalpiles. The sludges and concentrates fromwastewater treatment will also be added tothe disposal piles. In essence, this converts apoint source of pollution, which would behighly regulated under existing laws, to anonpoint discharge, which is not well-regu-lated at present. However, the treated waste-waters would be quite different from the rawstreams described in table 51. For example,most of the NH3 and H2S will have been re-moved from the gas condensates and recov-ered as byproducts. The CO2 will also havebeen removed and vented to the atmosphere.The concentration of NH3 could be further re-duced by biological treatment and by usingthe treated condensates as cooling water.The small quantity remaining may be usefulas fertilizer for reclaiming the waste disposalareas. Most of the potentially harmful organ-


ic compounds could be removed by biologicaltreatment and the more resistant ones by ad-sorption. However, some organic matter islikely to reach the shale disposal area. It isnot known whether the organics will remainlocked within the shale pile or will beleached.

Similar treatment could be used for the re-torting and upgrading condensates, althoughthe chemicals in the retort condensate couldpose some special treatment problems. Ifthermal sludge systems were used, both theinorganic and the nonvolatile organic contam-inants would be reduced to a stable sludgesuitable for disposal in a sanitary landfill orin a hazardous-waste disposal area. The vola-tile organics would be entrained in the steamand subsequently incinerated in the retorts.

Reinfection

Reinfection may be legally allowed if thequality of the injected water is at least ashigh as that in the affected aquifer. Injectionof condensates or other highly contaminatedwastes would not be permitted without a highdegree of treatment, However, mine drainagewater might be reinfected if it had not beendegraded by evaporation or chemical changewhile on the surface. Otherwise, it firstwould have to be treated or diluted.

Until commercial-scale oil production be-gins, essentially all mine drainage water willrequire disposal, probably by reinfection. It isgenerally assumed that the chemicals in thedrainage water would not cause significantchanges in the quality of the source aquifers.However, water quality could be degradedbecause of the increased ground water flow,the exposure of new mineral surfaces byfracturing, and the changes in undergroundmicrobial populations. If such changes oc-curred, the treatment or disposal conditionswould have to be adjusted to compensate forthem. 51 This might include treating the drain-age to a purity higher than that of the sourceaquifer.

Monitoring Water Quality

Because much surface water comes fromground water discharge, it is necessary tomonitor both surface and ground water tohelp prevent environmental damage. Moni-toring provides a continuous check on compli-ance with regulations, a record of changes re-sulting from development, and a measure ofthe effectiveness of pollution control proce-dures.

Surface Water Monitoring

Surface water monitoring should include:●

●

●

●

A

instream sampling and chemical anal-ysis to detect and characterize pollut-ants of point and nonpoint origin:detection of spills and faulty contain-ment structures that could result in ac-cidental discharges;measurement of streamflows to assesseffects of dewatering operations andconsumptive uses; andmeasurement of aquatic biota to deter-mine the changes resulting from develop-ment,

monitoring program is defined by thenumber and location of sampling stations, theparameters measured, the sampling frequen-cy and collection methods, the accuracy andprecision of the analytical techniques, andthe quality assurance safeguards. Tradition-al monitoring methods may not be well-suitedfor the oil shale situation. The uncertainpollutant release rates and pathways and thewide variations in regional water quality,complicate the development of a suitable pro-gram and limit the use of conventional tech-niques.

The number and location of sampling sta-tions depend on the objective of the monitor-ing program. For example, if the objective isto detect changes over an entire basin, thestations would be located in the lowerreaches of major tributaries. They could de-


tect major changes but would be unable topinpoint their cause. In contrast, stationsnear pollution sources could both measurethe local effects of pollutant discharge andidentify the source. An oil shale programcould include stations on major streams, aswell as on the minor tributaries that draineach development site. Special stations arealso needed near solid waste disposal areasto detect leaching.

The selection of chemical, physical, andbiological parameters to be measured will bebased on the types and concentrations of pol-lutants that might be discharged, the ease ofanalysis, and the characteristics of the waterin the affected streams and aquifers. Thepossible parameters include the concentra-tions of the pollutants themselves as well asthe levels of “indicator” parameters that pro-vide a measure of the potential environmentaldisturbance. These include pH, dissolved ox-ygen, hardness, temperature, flow rate, andthe characteristics of the aquatic biota.

Biological parameters are especially usefulbecause they reflect the stability and re-sponse of the ecosystem. Aquatic organismsare natural monitors of water quality sincethey respond in a predictable manner to thepresence of most types of pollutants. Changesmay indicate problems that are not easilydetected by direct measurements of waterquality. For example, heavy metals and someorganic compounds tend to concentrate in thebiota. Their levels in the tissues of certainfish could help predict pollution concentra-tions that are not readily measurable in thewater itself. Communities that could be moni-tored include invertebrates, fish, algae, andbacteria.

The sampling frequency can also vary.Ephemeral tributaries, for example, could bemonitored only during periods of heavy rain-fall or snowmelt; mainstream tributariescould be monitored continuously. Frequentmonitoring of all possible parameters wouldbe very expensive and time-consuming.Therefore, priorities must be established onthe basis of cost, utility of the data, and thepotential for severe environmental impacts.

Ground Water Monitoring

Observation wells are used to detecttrends in water quality and to measure the ef-fects of operations such as wastewater rein-fection. The locations of the monitoring sta-tions should be selected according to:

● the locations of the potential pollutantsources;

● the geology and hydrology of the site tobe monitored;

● the probable movement and dispersionof pollutants underground; and

● the potential for hydrologic disturbancesof, for example, dewatering wells.

EPA has developed a monitoring methodologyfor the oil shale area.52 The important con-siderations are:

●

●

●

●

●

●

The

the identification of potential pollutants;the definition of hydrogeology, groundwater use, and existing quality;the evaluation of the potential for in-filtration of wastes by seepage;the evaluation of pollutant mobility inthe affected aquifers;the priority ranking of pollution sourcesbased on the mass, persistence, toxicity,and concentration of the wastes; theirmobility; and their potential for harm towater users; andthe design and implementation of pro-grams for near-surface aquifers, deepaquifers, and injection wells.

siting of wells for near-surface aquifersis extremely important. They should beplaced down the ground water hydraulic gra-dient (i.e., “downstream”) from possible pol-lution sources such as reinfection wells, res-ervoirs, and disposal piles. The wells shouldallow sampling from different depths, and thechemical and physical parameters should beselected according to hydrological character-istics as well as the properties of potentialpollutants. Deep aquifers should be moni-tored near dewatering wells, in situ retorts,and reinfection wells. Monitoring of salinity,TDS, and water level should be emphasized.Monitoring deep aquifers in the Piceancebasin is especially difficult because the

— —

Ch, 8–Environmental Considerations ● 311

ground water flows through fractures andfaults and not through the more common uni-formly porous media, A further complicationis the different permeability of adjacentstrata. Even flow rates are hard to measurein a fractured-rock system, and it is difficultto properly site the monitoring stations.

The monitoring of surface and ground wa-ter quality is exemplified by the program onFederal lease tract C-b that has been under-way since 1974. The sampling schedule andwater quality parameters are listed in table65. Thirteen surface water gauging stationshave been constructed: nine on ephemeralstreams and four on perennial drainages.Nine springs and seeps are also monitored.Temperature and conductivity are measuredcontinuously at all stations on the perennialstreams. Dissolved oxygen, pH, and turbidityare measured continuously at several ofthese stations; other parameters are meas-ured monthly, quarterly, or semiannually.

Water levels in alluvial aquifers are meas-ured continuously at 18 test wells. Conduct-ance, pH, temperature, and dissolved oxygenwill be measured monthly. The quantity andquality of water in the deeper bedrock aqui-fers are measured at 17 wells in the upperaquifer and 14 in the lower aquifer. Samplesare obtained for water quality twice a year,and water levels are measured monthly. Wa-ter quality is also measured in reservoirs,waste disposal piles, and mine sumps.

Information Needs and R&D Programs

Insights into the water quality impacts ofoil shale development have been obtainedfrom laboratory and pilot plant studies, froma few field tests in the Piceance basin, andfrom experience in related industries. Addi-tional measurements and R&D programs areneeded to help reduce the level of uncertain-ty. Uncertainties will remain, however, untilexperience has accumulated from commer-cial-sized modules and plants.

Need for Reliable Data on Wastewater Quality

Reliable data are lacking on the charac-teristics of the gas, retort, and upgradingcondensates from all of the proposed de-velopment technologies. The data should beobtained with pilot plants that integrate sev-eral streams and several control devices andthat simulate commercial-scale conditions.In commercial plants, wastewaters may bemixed and the interactions of contaminantsfrom the different streams will affect treat-ability. Therefore, analyses of separatestreams are not sufficient.

More reliable estimates are needed of thequality and quantity of the mine drainagewater that will be encountered in specificareas. This information would help determinehow the water would have to be treated forsurface discharge, and would allow a com-parison to be made between surface dis-charge and other disposal methods.

Studies of leachates are also needed; inparticular, on their ability to penetrate thelinings of disposal ponds and catchment ba-sins.

Need for Assessing Control Technologies

Although individual methods have beentested successfully on a small scale, the per-formance of an integrated treatment systemhas yet to be evaluated with actual effluentstreams. This could be done, for example, bytesting relatively inexpensive pilot-scale sys-tems as part of a retort demonstration pro-gram. These tests would help determine, forexample, if the dissolved organics in retortcondensates can be adequately controlledwith a series of conventional treatment proc-esses. The distribution and control of traceelements could also be assessed.

Need for Cost Information

According to present estimates, wastewa-ter treatment costs are expected to be only asmall fraction of the total cost of shale oil pro-

—— —— — -.. —


Table 65.–Sampling Schedule Summary for Surface and Ground WaterMonitoring Program at Tract C-b During Development Phase

Surface water Seeps and springs Ground water

Alkalinity ., ...Ammonia ., ., ~ .,Arsenic. ... ., ., . ., .,Barium . ., ... .,B e r y l l i u m . . .B i c a r b o n a t e . . . . . . . , . . , , , , , , . ,B A D . , . , . , . , , . . . . . . , , . . . . .Boron ., ., ., .C o b a l t . . , . . , . , , , . , , , , . . , , . , , . . , , .C o l o r . , . , , . , , , , . , , . . , . . . . . , , , , , ,COD.. . . . . . . . . . . .Coliform, total and fecal ., .,,.,,,,,. .,Conductivity, specific, ,,. ,,Copper. , .,, .,... ,.,.,, . .C y a n i d e . . , . , , . . , , , , , . . , . , , , , , . ,D i s s o l v e d o x y g e n . , , . , .F l u o r i d e . , . , . , .H a r d n e s s , . . , . , , , ’ , ” ’ ” .I r o nL e a d . . . . ’ . . , , . , , , , ‘ ,Lithium. ,.,, ,.,, ,,..,,.Magnesium, ,.,’.. . . . . .M a n g a n e s e , , , ,Mercury. ., . . . . ., .,Molybdenum .,.., . . . . . . ,,,Nickel. , ,,. ,., . . . , , .Nitrate . . . . . . . . . . . ,,.Nitrogen (Kjeldahl), ,.,,.Odor .,,,Oil and grease, , , .,,, ,,.Phosphate, , ...,, ,,.Pesticides. .,... ,.., ,,.Phenol ,.. ,,,. .,,. .,,,Potassium, ., ., ., ..., ., .,Radiation, alpha .,, ,,, ,,,R a d i a t i o n , b e t a . , . ,Sediment ,.. ,. ,“.Silica ..,,, ,,. ,.., .,,,,Sulfate ,. ,, ....,,S u l f i d eS u s p e n d e d s o l i d sT u r b i d i t y . . . . , . . , . , , , , , , , , , , , . . ,PA, ,, ., ..,.,.,, ..., ,,,T o t a l d i s s o l v e d s o l i d s . . , , , .Water level .,Stream flow. ,, . . . . . . . ..,’W a t e r t e m p e r a t u r e . , . .D i s s o l v e d o r g a n i c c a r b o n . , . ,

M(Z), Q(O,PC)M(Z)Q(o,PC)M(Z)O(o,PC)

—Q

M(Z) Q(o,PC)—

M(Z~Q(o,PC)——Qo.QQ

M(Z)Q(o,PC)M(Z), Q(o,PC)

——QQ

M(Z), Q(o,PC)M(Z) Q(o,PC)

QQ—

M(Z~Q(o.PC)M(Z), Q(o,PC)

—Q

M(Z~Q(o,PC)—Q

M(Z), Q(o,PC)QQ

M(Z), Q(o,PC)M(Z), Q(o,PC)M(Z), Q(o,PC)

o——

M(Z), Q(o,PC)M(Z), Q(o,PC)

—M(Z) Q(o,PC)M(Z) Q(o,PC)M(Z) Q(o,PC)

oQQ———QQ——QsMQ—MQQQQQQQQQQQQ—Q—.QQss——o———

M,QQ—

Q,SA,AM,Q

s

Q(Al), SA(Aq)Q(Al), SA(Aq)Q(Al), SA(Aq)( L i s a

A(AI)—

SA(Al), SA(Aq)Q(Al), SA(Aq)

SA(Aq)—

Q(Al), SA(Aq)—

Q(AI)Q(Al), SA(Aq

—M(AI)

Q(Al), SA(AqQ(Al), SA(AqQ(Al), SA(AqQ(Al), SA(Aq)Q(Al), SA(Aq)O(Al), SA(Aq)Q(Al), SA(Aq)Q(Al), SA(Aq)Q(Al), SA(Aq)Q(Al), SA(Aq)Q(Al), SA(Aq)Q(Al), SA(Aq)

—Q(Al), SA(Aq)

—SA(Aq)

A(Al), SA(Aq)Q(Al), SA(Aq)

SA(Al), SA(AqSA(Al), SA(Aq

——

Q(Al), SA(Aq)———

M,Q(AI)Q(AI)

M E S A—

M, Q(Al), SA(Aq)SA(Al), SA(Aq)

KEY A =AnnUa~y (Z) =Maorgaglng slationson~SA = Semiannually (o) =Aflgagmg stations except major stahonsS= Semimonthly (PC) =F?ceance Creek gaging stationsO =Ouarferiy (Al) =Alluwal wellsM =Monlhly (Aqj =Oeepaquders

SOURCE E R Bales andT L Thoem(eds ) Pollution Con/ro/Gu/dancelor Oti Sha/e Deve/oprnerrl Apperrd/ces /o the l?ewsed L%a/(Reporl, comptiedbyJacobs Envwonmental Orw~onfor Envvonmental Protection Agency C{nclnnah Ohio July 1979 pp C-84-C-85

duction. However, inadequate attention to Lower cost treatment options should alsowater management could seriously impede a be explored. For example, the thermal sludgeproject’s construction and operation. Thus, system could significantly reduce treatmentwater treatment although not costly by itself costs by raising steam directly from processcould ultimately cause substantial cost esca- condensates. Another promising procedurelations. is the removal of dissolved organics from


treated condensates in the cooling water cir-cuit.

Discharging suitably treated wastewaters(especially excess mine water) to surfacestreams should be investigated as a mecha-nism for supplementing the region’s scarcewater resources. Some of the contaminants inthe treated wastes may require special atten-tion, and means to remove them should be ex-plored.

Need for Evaluating the Potential Impactsof Effluent Streams

Information is needed on the impacts of thepollutants on the environment. In particular,research is needed on the effect of the leach-ing of spent shale and other solid wastes onsalinity, sediment loading, temperature, nu-trient loading, and microbial populations ofsurface waters. This work should address theimpacts that might occur both during theoperation of a facility and after the facility’suseful lifetime.

Specific R&D Needs

Research is needed in the following speci-fic areas:

●

●

●

●

●

●

characterization of the wastewaters, es-pecially for the presence of trace metalsand organic chemicals produced by eachretorting process;determination of the applicability of con-ventional treatment methods to oil shalewastewater and development of newtreatment methods if necessary;determination of the changes in groundwater quality and flows resulting frommine dewatering;development and demonstration of meth-ods to prevent leaching of MIS retorts byground water;studies to simulate and test the percola-tion of rainfall and snowmelt throughspent and raw shales and native soilsand to assess resulting leachates;standardization of leachate samplingtechniques;

development of reliable models and test-ing them under simulated worst caseconditions, such as massive failure of acontainment structure; andresearch on the restoration of aquifersdisturbed by in situ processing,

Current R&D Programs

Below is a partial listing of the ongoing andproposed R&D programs by the Federal Gov-ernment and the private sector:

Under EPA grants, Colorado State Uni-versity is studying the water qualitywithin the oil shale areas, the leachingcharacteristics of raw and retorted oilshale, and the surface stability and wa-ter movement in and through disposalpiles. Specific objectives include devel-oping procedures for assessing the quan-tity and quality of surface and subsur-face runoff from solid waste piles.Under an EPA contract, TRW and DRIare studying the environmental impactof oil shale development, including anevaluation of technologies for waste-water control.DOE’s Office of the Environment is as-sessing water quality aspects of theParaho process.DOE and the State of Colorado are devel-oping a program related to water pollu-tion from MIS retorting.Under EPA contracts, the Monsanto Re-search Corp. is investigating the treat-ment of retort wastewaters and is study-ing the potential of in situ retorting forair and water pollution.The National Bureau of Standards, in co-operation with EPA and other agencies,is developing methods for measuring theenvironmental effects of increased ener-gy production.In its oil shale program managementplan, DOE has proposed to:—assess the effect of mine and retort

backfilling on ground water quality;—study the leachability of raw and

spent shale and the effect of disposalon surface and ground water quality;

6 3-89B ‘ - 80 - ? :


●

●

—investigate the need for long-termcare of surface disposal areas; and

—design a solid waste disposal plan fora commercial MIS facility.

The National Science Foundation i ssponsoring work to characterize the con-taminants in spent shale and to developtechniques for managing them.EPA is preparing a pollution controlguidance document for an oil shale in-dustry, that will consider all aspects ofsurface and ground water quality.

Findings on Water Quality Aspects ofOil Shale Development

Water quality is of major concern in the oilshale region, especially in regard to thesalinity and sediment levels in the ColoradoRiver system. Oil shale development has thepotential for water pollution, the extent ofwhich will depend on the processing technol-ogies employed, the scale of operation, thetypes and efficiencies of the pollution controlstrategies used, and the regulations that areimposed.

Surface discharge from point sources isregulated under the Clean Water Act, andground water reinfection standards are beingpromulgated under the Safe Drinking WaterAct. Solid waste disposal methods may besubject to the Toxic Substances Control Actand the Resource Conservation and RecoveryAct. The general regulatory framework istherefore in place, although no technology-based effluent standards have been promul-gated for the industry under the Clean WaterA c t .

Developers are currently planning for zerodischarge to surface streams and to reinjectonly excess mine water. Most wastewaterwill be treated for reuse within the facility;untreatable wastes will be discarded in spentshale piles. The costs of this strategy are lowto moderate, and development should not beimpeded by existing regulations if it is imple-mented.

A variety of treatment devices are avail-able for the above strategy, and many of them

should be well-suited to oil shale processes. Itis less certain that the conventional methodswould be able to treat wastewaters to dis-charge standards because they have not beentested with actual oil shale wastes under con-ditions that approximate commercial produc-tion. Furthermore, no technique has beendemonstrated for managing ground waterleaching of in situ retorts, nor has the ef-ficacy of methods for protecting surface dis-posal piles from leaching been proven. It isnot known to what extent leaching will occur,but if it did, it would degrade the region’swater quality.

Although control of major water pollutantsfrom point sources is not expected to be asevere problem, less is known about controlof trace metals and toxic organic substances.Research is needed to assess the hazardsposed by these pollutants and to developmethods for their management. Other labora-tory-scale and pilot plant R&D should be fo-cused on characterizing the waste streams,determining the suitability of conventionalcontrol technologies, and assessing the fatesof pollutants in the water system. Such workis underway; its continuation is essential toprotecting water quality, both during the op-eration of a plant and after site abandon-ment.

Policy Options forWater Quality Management

For Increasing Available Information

Options for increasing the overall level ofinformation regarding pollutants, their ef-fects, or their control include the evolution ofexisting R&D programs, the improved coordi-nation of R&D work by Federal agencies, in-creasing or redistributing appropriations toagencies to accelerate their surface andground water quality studies, and the pas-sage of new legislation specifically tied toevaluating water quality impacts. For exam-ple, pioneer plants receiving Federal assist-ance could be required to monitor water qual-ity effects, with particular emphasis on non-point discharges. Procedures for implementa-


tion could be similar to those for the existingFederal Prototype Leasing Program. Mecha-nisms for implementing these options are sim-ilar to those discussed in the air quality sec-tion of this chapter.

For Developing and EvaluatingControl Technologies

The Government could expedite the avail-ability of proven controls by accelerating itsefforts to design, develop, and test treatmenttechnologies for oil shale wastewaters. To bemost effective, this work would have to becoordinated with private efforts to developthe oil shale processing methods. This couldbe done under cost-sharing arrangements, in-cluding tests at the sites of retort demonstra-tion projects. (EPA is presently conducting aprogram for retorting wastewaters under acontract with Monsanto Research Corp. )

For Developing Regulatory Procedures

The present approach could be followed inwhich regulations evolve as the industry andits control technologies develop, An approachcould also be used in which standards wouldbe set that would not change for a period ofsay, 10 years, after which they could be ad-justed to reflect the experience of the indus-try. This would remove most of the uncertain-

ty about environmental regulations that isnow deterring developer participation. How-ever, the standards would have to be careful-ly established to assure that they were bothattainable at reasonable cost and adequate toprotect the environment. Mechanisms for im-plementing improved regulation of nonpointdischarges include extension and modifica-tion of the Surface Mining Control and Recla-mation Act for oil shale, special controls reg-ulating nonpoint discharges under the CleanWater Act, or applying the Resource Conser-vation and Recovery Act waste disposalstandards to low-grade/high-volume mate-rials.

For Ensuring the Long-Term Management ofWaste Disposal Sites and Underground Retorts

These areas may require monitoring formany years after the projects are completed.Long-term management could be regulatedunder the Resource Conservation and Recov-ery Act, which allows EPA to set standardsfor the management of hazardous materials,including mining and processing wastes. Nosuch action has yet been taken by EPA, butCongress could direct it to do so. Congresscould also require the developers to guaran-tee such management by incorporating ap-propriate provisions in any bill encouragingoil shale development.

Safety and HealthIntroduction ●

Anticipating occupational and environmen- ●

tal health and safety hazards is an importantconsideration in the development of an oil ●

shale industry. Anticipation and planning, es-pecially in the early phases of the industry, ●

should guide efforts to reduce health andsafety risks and costs to society. To bring at- ●

tention to known hazards, and to point out po-tential ones, this section covers the following ●

subjects: ●

the health and safety hazards associ-ated with oil shale operations;the environmental risks if contaminatedair and water are released;the applicable Federal health and safetylaws, standards, and regulations;the control and mitigation methods thatcould be applied to these risks;the issues regarding the coordination ofmonitoring and education efforts;the R&D needs; andthe policy options.

316 “An Assessment of Oil Shale Technologies

Safety and Health Hazards

Occupational Hazards

Workers will be exposed to a number of oc-cupational safety and health hazards duringthe construction and operation of an oil shalefacility. Many of these hazards—such asrockfalls, explosions and fires, dust, noise,and contact with organic feedstocks and re-fined products —will be similar to those asso-ciated with hard-rock mining, mineral proc-essing, and the refining of conventional petro-leum. However, due to the physical and chem-ical characteristics of shale and shale oil, thetypes of development technologies to be em-ployed, and the scale of operations, oil shaleworkers might be exposed to unique hazards.They will be discussed as follows: safety haz-ards that might result in disabling or fatal ac-cidents; and health hazards stemming fromhigh noise levels, contact with irritant andasphyxiant gases and liquids, contact withlikely carcinogens and mutagens, and the in-halation of fibrogenic dust.

SAFETY HAZARDSMining.-The similarity of hard-rock min-

ing to underground or open pit oil shale min-ing makes it possible to project likely occupa-tional safety risks. During mining, accidentsresult from rock and roof falls, explosionsand fires, bumps and falls, electrocution,heavy mining equipment, and vehicular traf-fic. Hard-rock mining is a high-risk occupa-tion; fatalities are five times more frequent inthe mining and quarrying industry than inmanufacturing. The frequency of disablinginjuries from underground mining (excludingthe coal industry) is two and a half timeshigher than from manufacturing. 53 M i n i n gcoal is even more dangerous.

While most hazards to oil shale minerswould be similar to those experienced byhard-rock workers, some are unique to oilshale. A number of the oil shale facilities areplanning to use MIS processes in which partof the deposit is mined out and the remainderis then rubbled and burned underground. Thehigh temperatures and fires involved in MIS

may expose miners to risks that are not ex-perienced in other underground mining ac-tivities. The hazard of mine flooding is notunique to oil shale, nor would it be encoun-tered in all oil shale mines. However, it couldbe severe in mines that are developed withinground water areas. While the mining zoneswould be dewatered before mining could be-gin, there could be flooding if the pumpsfailed.

Retorting and refining.—Potential hazardsassociated with the retorting and upgradingof shale oil include explosions, fire and heat,bumps and falls, electrocution, and handlinghot liquids. However, the degree of risk forworkers involved in the processing of oilshale and its derivatives would not be ex-pected to be so high as in mining.

The processes involved in retorting and up-grading (e.g., materials handling, crushing,solids heating and cooling, waste disposal,and the handling of hot and hazardous liq-uids) are generally similar to those used inother operations such as mineral processing(e.g., limestone calcining, roasting of taconiteand copper ores, and leaching) and conven-tional petroleum refining. Although no com-parative study has been undertaken, thereare few unique features associated with re-torting, upgrading, and refining that wouldjustify expecting higher worker safety risksthan those in similar industries.

HEALTH HAZARDS

Mining. —During oil shale mining, as dis-cussed in the section of this chapter on airquality, hazardous substances including sili-ca dust will be generated by blasting anddrilling. In addition, blasting, raw shale han-dling and disposal, and other activities at theminesite will produce fugitive dust. Silica-containing dusts are noteworthy becausethey have been the single greatest health haz-ard throughout the history of undergroundmining. Silica is highly toxic to alveolarmacrophages—’’scavenger” cells that moveabout on the inside of the lung and engulf andremove foreign particles that might damagethe lung. Silicosis, “shalosis,” and chronic


bronchitis* are among the diseases that mayresult from the inhalation of oil shale dust.

A survey conducted by the U.S. PublicHealth Service (USPHS) between 1958 and1961 found excessive dust levels in 6 out of 67inspected mines. 54 The chest X-rays of 14,076miners employed in 50 hard-rock mines indi-cated that 3.4 percent had silicosis. ss * *These measurements were made before mod-ern mine hygiene practices were required bythe relatively recent occupational safety andhealth regulations and a more recent studyundertaken by the Mining Safety and HealthAdministrat ion showed marked improve-ments in mine dust levels. This study exam-ined 22 hard-rock mines, 8 of which were in-cluded in the USPHS study, and found none ofthem in violation of the dust standards, 56)** *

Although few studies have been under-taken on the direct association between oilshale mining in the United States and the in-cidence of lung disease, there are studies onthe prevalence of lung disease in oil shaleminers in Estonia. Estonia mined 25 milliontons of oil shale in 1973, and has had oil shaleoperations for several decades. While the re-sults of the Estonian studies are more intrigu-ing than convincing, they do suggest an asso-ciation between oil shale mining and pulmo-nary fibrosis— an increase in the amount offibrous material in the lung. One study alsoindicated that chronic bronchitis was 2 to 2-1/2times more prevalent in 189 Estonian oil shaleminers than in a similarly aged control popu-lation.” (A similar degree of excess bronchitishas been observed in coal miners in the

*Sili~osis is a ~is~blin~ fibrotic disease of the lungs causedby inhalation of silica dust and marked by shortness of breath.“Shalosis” is a disease of the lungs and is related to specific ex-posures of oil shale mine dust. It resembles silicosis: its ex-istence as a specific disease remains to be proved. Inflammationof the bronchial tubes, or anv part of them, is known as bron-chitis.

**The 3.4 percent is probably a low estimate; generally sickindividuals who have left the work force or moved for healthand other reasons are under-represented in such surveys. Ifsuch individuals had been examined the incidence of silicosismight have been higher.

***This study is expected to be released in the near futurealong with a companion study undertaken by the National Insti-tute of Occupational Health and Safety which examines thehealth status of miners from 22 hardrock mines.

United States and England,58 and in goldminers in South Africa. 59)

In another study, postmortem examinationof 30 Estonian oil shale workers who died ofaccidents and various other diseases60 foundthat all had pulmonary fibrosis and one-fourth displayed classic silicotic nodules. * Anexamination of 1,000 Estonian oi l shaleworkers failed to reveal any cases of pneumo-coniosis, a pulmonary disease caused by in-haled dusts. However, the workers had beeninvolved in the industry for only 5 to 14 years.Twenty years of exposure are usually re-quired for the symptoms of the disease to bedetected by a chest X-ray. Because Estonianindustrial hygiene standards are not known,the Estonian studies can only suggest an asso-ciation between oil shale mining and lung dis-ease. The Estonian studies provide no infor-mation about the risk levels to be expected inmines maintained under U.S. health and safe-ty standards.

Studies of occupational diseases among oilshale miners in the United States have beenlimited because relatively few people haveworked in the industry. A study was under-taken involving miners from the oil shale re-search center at Anvil Points, Colo., whichhas operated intermit tent ly s ince 1946.Eighty-six workers were identified, but only39 of them had been exposed to oil shale forone or more years. Those 39 were comparedwith 26 other workers from the facility (e.g.,office workers, administrators) who had notbeen directly involved in the mining opera-tions. Results showed a twofold higher inci-dence of pneumoconiosis in the oil-shale ex-posed population. However, the interpreta-tion of these results is complicated by the factthat most of the oil shale miners had previous-ly worked in uranium-vanadium mines or mill-ing operations which are known to be causesof pneumoconiosis.61 Further evaluation ofthese populations was not performed becauseof the age of the workers, their varying levelsof exposure, and their limited experience inoil shale mining.

*Silicotic nodules are small lumps on the surface of the lungformed as a response to deposition of silica specks.


A separate study of employees at the samefacility between 1974 and 1978 found no ad-verse health effects.62 An examination of thedeath certificates of 167 oil shale workers un-dertaken by the National Institute for Occu-pational Safety and Health (NIOSH) failed toreveal any association between oil shale ex-posure and respiratory diseases.63 Because ofthe limited number of workers studied, theirrelatively short exposures to oil shale mining,and in some cases their exposures to otherkinds of mining, no firm conclusions can bedrawn from these studies.

Some animal studies have demonstratedrelationships between oil shale exposure andrespiratory diseases, but the results conflictwith those of other experiments, making itdifficult to draw conclusions. One study indi-cated that Estonian oil shale had a weak fi-brogenic* action in rats; both oil shale andspent shale ash produced pulmonary fibrosisin white rats after the dusts were depositedinto the trachea.64 Another study reportedpulmonary effects when Syrian hamsterswere exposed via intratracheal administra-tion or inhalation to finely ground oil shaledust and retorted shales.65 66 Increased alveo-lar microphage activity was also noted. Thesame study found that retorted shale dustwas associated with inflammation, and fre-quently caused increases in the fibrous mate-rial in the lung (fibrosis] and excessivegrowth of cells that line the lung cavities (epi-thelial hyperplasia). However, a 2-year studywith rats, which evaluated the effects of rawor spent shale dust instilled intratracheally inmultiple exposures over an 8-month period,found essentially no pulmonary fibrosis. Theinvestigator considered the results to be neg-ative. 67

Another area of concern is the possible ex-posure to carcinogens (e.g., polycyclic aro-matic hydrocarbons—PAHs) and trace ele-ments that might be produced during mining.The NIOSH mortality study mentioned earli-er found that the percentage of oil shaleworkers who had died from colon and respi-

*A fibrogenic substance is conducive to the generation offibrous materials in the respiratory tract.

ratory cancers was greater than the percent-age in the white male populations of Coloradoand Utah.68 Whether oil shale exposure con-tributed to the higher incidence is unclear,and the incidence rate among miners was nothigher than that of the white male populationin the United States.

A cancer morbidity study undertaken bythe Rocky Mountain Center for Occupationaland Environmental Health found more cyto-logical atypia* in the sputum and urine of oilshale miners than among controls, but no as-sociation was found between exposure andskin diseases. These data will be furtherstudied to identify any associations betweensuch abnormalities and occupational ex-posures. Animal studies undertaken to datehave not demonstrated that oil shale dust iscarcinogenic.

A third potential health hazard to oil shaleminers is exposure to excessive noise levels,particularly in underground operations car-ried out in relatively confined spaces. Noisearises from numerous sources such as boost-er fans, pneumatic drills, blasting, conveyors,and mining machines. The Bureau of Minesstudied 19 pieces of diesel-powered miningequipment and found only 2 had noise levelsbelow the current standards (90 decibels),and one of these exceeded the standard in anunderground environment. One study esti-mated that of the 37,000 workers employed in650 metal and nonmetal mines, approximate-ly 14,000 (38 percent) were exposed to diesel-powered equipment noise levels greater thanthe standard.** Of these, 2,430 (17 percent)were overexposed on a time-weighted-aver-age basis.69 Evidence indicates exposure tonoise from a large number of mining ma-chines would produce hearing loss if the ex-posures exceeded 8 hours per day.70 Highershort-term noise exposures may occur during

*Cytological atypia are premalignant cell types observed inthe examination of the body fluids.

**A major health issue is the long-term effect of diesel smokeexposure in underground mining environments. The NationalAcademy of Sciences is conducting a study in this area whichwill be released in the near future. The health implications ofdiesel equipment used in underground oil shale mines is un-known at this time.


blasting. High noise levels are a potential haz-ard not only to hearing, but to the cardiovas-cular and nervous systems as well, and posea safety hazard.

Retorting and refining. —Retorting oilshale at high temperatures forms PAH-con-taining carcinogens of which 3,4-benzo(a)py-rene (BaP) is the most studied. PAHs are amajor potential health hazard for retortingand refining workers in the oil shale industrybecause of their carcinogenicity. The prob-lems that might be encountered in oil shale re-fining are similar to those of conventional oilrefineries, where liquids and gases are trans-ported in airtight pipes under strict mainte-nance to detect and repair leaks.

Crude oil contains an enormous variety ofpotentially hazardous compounds, Even moreare produced during refining. Work crews in-volved in inspection, repair, and maintenanceare the most likely to be exposed to PAHs.Other hazardous substances found in crudeoil include chlorine, sulfur, nitrogen, andheavy metals (e.g., vanadium, arsenic, nickel,and cobalt). Toxic contaminants evolved dur-ing the refining process include H2S, hydro-gen chloride, hydrochloric acid, SO2, sulfuricacid, methane, ethane, methanol, nitric acid,NOX, mercaptans, CO, and benzene.

The high rate of cancer of the scrotumfound in 19th century chimney sweeps andmulespinners* is of historical interest be-cause it indicates that long exposure of scro-tal skin to PAH-containing oils and soots cancause cancer. In addition to scrotal cancer,cancers of the skin, lung, and stomach havealso been observed after latent periods of upto 20 years following exposure to PAH-con-taining substances. While the known carcino-gen BaP was identified in Scottish shale oil,71

a study found only a low incidence rate (lessthan 0.1 percent per year) of skin cancer for5,000 Scottish oil shale workers between1900 and 1922.72

*Mulespinners were workers who lubricated the “mules”(spindles) in the Scottish spinning and weaving industry. Shale-derived lubricants were commonly used in this industry.

Refined Scottish shale oils were known tobe carcinogenic, but the disease was largelypreventable by personal cleanliness. It is be-lieved that the disease occurred because theworkers wore the same clothes on the job dayafter day. The clothing was rarely, if ever,laundered, and eventually it became impreg-nated with shale oil. Contact between thesoaked clothing and the areas where cancersoccurred was nearly continuous during eachworking day. This factor, coupled with thefact that daily bathing was rare, undoubtedlycontributed to the high incidence of cancer.

Two Estonian studies have shown an asso-ciation between oil shale processing andcancer. A study of 2,003 Estonian oil shaleworkers with a total of 21,495 person-yearsexposure during the period between 1959and 1975 found a significant excess of skincancer (fivefold for females and threefold formales). 73 An unusually high incidence ofstomach and lung cancer was found amongpersons in the rural areas of Estonia wherethe oil shale industry is located. ” There is noinformation on the working conditions in Esto-nian oil shale operations; nor are dataavailable on the ambient concentrations ofshale-derived pollutants in the vicinity of theplants. It is therefore impossible to relate theEstonian experience to problems that mightbe encountered in the United States.

Evaluating chemical carcinogenicity in ani-mal experiments is an accepted method forpredicting carcinogenicity in humans. Inves-tigations that tested the carcinogenicity of oilshale and shale oil in laboratory animals areshown in table 66. A conclusion that can bedrawn from these studies is that shale oil is acarcinogen when painted on animal skins.The experiment conducted by Biology Re-search Consultants (ref. 80 in table 66), inwhich hairless mice were bedded in raw orspent oil shale, found no carcinogenic hazard.However, this study did not examine the oilshale extracts (e.g., shale oil tar and coke)with which carcinogenicity has been associ-ated.

Both the Kettering Laboratory (ref. 79) andEppley Institute (ref. 81) studies conclusively


Table 66.–Animal Studies on the Carcinogenicity of Oil Shale and Shale Oil

OrgansNature of study Ref a Materials tested examined Tumerous animals/animals exposed

Skin painting study of mice, rats, and rabbits

Skin painting of mice



Skin painting of mice (Kettering study)

Exposure to shale dust (Biology ResearchConsultants)

Skin painting of mice (Eppley study)

Intratrachael Instillation in hamsters (Eppleystudy)

75

76

77

78

79

79

79

79

Scottish shale OilS “green 011’

‘‘blue oil ’‘‘unfinished gas oil’‘‘Iubricatmg oil

CHCI 3 extract of Scottish oil shaleScottish shale oil

Shale oil

Shale oilComposite petroleum control

Crude shale oilHydrotreated oilBaP control

Oil shale powderOil shale powderSpent shale powderSpent shale powderPowdered corn cobs (control)Powdered corn cobs (control)

Benzene extract of shale oil cokeTOSCO II effluentBenzene extract of raw shale oilBenzene extract of spent shaleBenzene controlNone (control)

Raw oil shaleSpent shaleShale 011 cokeTOSCO II effluentBaP controlSaline controlNone (control)

skinskinskinskin

skinskin

skin

skinskin

skinskinskin

skinlungsskinlungsskin

lungs

skinskinskinskinskinskin

(b)(b)(b)(b)(b)(b)(b)

9/1001 2/100

1/503/50

0/206/10

1,284/10,000

(35%-90% tumerous)(0%-8% tumerous)

39/405/37

27/27

0/122/240/121 /240/1 26/24

48/501 /500/506/500/500/100

0/1000/1000/1000/ 100

27/1OO0/ 1000/200

aSee reference list bResplratory system

SOURCE Wllham Rom et al OcCuPdllOflallEflVlfOflmeflldl Healfh and .SaletY Aspecfs of a CO~rrJerCW 0// Wale lmlWy prePared for OTA by Rocky Mountain Center for Occupational and EnwronmentalHealth Unwerslty of Utah Oecember 1979

show that crude shale oil, shale oil tars, andshale coke have carcinogenic properties,which may be related to their BaP content.The second Eppley study (ref. 82), which in-vestigated respiratory system carcinogeni-city, found no effect. This contrasts to theskin exposure experiments. Whether or notoil shale and its derivatives are less of athreat to the respiratory system than to theskin deserves further study.

Although BaP may not be the only carcino-gen in shale oil and its products, it is probablythe most potent. The study summarized intable 67 shows that hydrotreating shale oil

Table 67.–Benzo(a)pyrene Content of Oil Shale andIts Products and of Other Energy Materials

Substance BaP concentration, p/ba

Raw oil shale ., . ., . . . 14T O S C O I I r e t o r t e d s h a l e , . , . , 28TOSCO II atmospheric effluent . . ., 140T O S C O I I r e t o r t c o k e . 129Raw shale oil from Colorado, ., ., ., 3,200Hydrotreated shale 011 (0.25% N 2) ., 800Hydrotreated shale 011 (0,05% N 2) ., 690Coal ., ., ., 4,000Libyan crude 011 ., 1,320

A s p h a l t f r o m c o n v e n t i o n a l c r u d e 10,000-100,000

aParis per bllllon

SOURCE R M Coomes Carcmogenlc Tesflng of 011 Shale Materials TweMh 0// Sha/e Syrr-poswm Proceedings Golden Colo The Colorado School o! Mines Press November1979


significantly reduces its BaP content,’{ Such areduction should be reflected in a lessening ofits carcinogenicity, This predicted effect ofhydrotreating was confirmed by the animaltests of the Kettering experiment (ref. 79,table 66).

The Estonian epidemiological studies andthe animal studies show that crude shale oil,shale oil tars, and shale coke are all car-cinogenic. Most of the studies to date suggestthat carcinogenicity is restricted to the skin.Occupational skin diseases from exposure tocertain industrial oils have long been a prob-lem, as was seen in the case of the scrotalcancer among chimney sweeps, One studyshowed that the effects of oil contact with theskin range from acute inflammation to kera-tosis (pitch warts which are regarded as apremalignant skin change.)84 Studies of oilshale retorting workers in the United Statesin the early 1950’s did not reveal any prob-lems with occupational skin disease, butworkers were exposed for a short time only. 85

A synergistic relationship has been foundbetween the ultraviolet radiation in sunlightand coal-tar pitch volatiles in causing skindiseases. A similar synergism might cause oc-cupational skin diseases in oil shale workerson the Colorado plateau, where ultravioletradiation levels are higher than at lower ele-vations.

Refining shale oil will be similar to otherrefining operations. Available epidemiologi-cal studies do not lead to clear-cut conclu-sions about relationships between working inrefineries and cancer. A retrospective mor-tality study sponsored by the American Petro-leum Institute that covered 17 U.S. oil refin-eries and over 20,000 workers was reportedin 1974,86) The study group included everyworker employed in the refineries for at leastone year between January 1, 1962, and De-cember 31, 1971. A 94-percent followup wasobtained. There were 1,165 deaths; 1,145death certificates were obtained. The stand-ardized mortality ratio (SMR) for all causes ofdeath among refinery workers was 69.1 com-pared with the base rate of 100 for the U.S.male population. The lower death rate among

refinery workers was attributed to the“healthy worker effect;” i.e., employed work-ers are healthier on the average than the gen-eral population. Respiratory cancer in-creased with increasing exposure to aro-matic HC, but was still lower than found inthe general population (SMR of 79.9).

On the other hand, two epidemiologicalstudies published by Canadian investigatorsshowed an increased cancer risk for refineryworkers. In a group of 15,032 male employeeswho worked for the Imperial Oil Co. between1964 and 1973, there were 1,511 deaths.Eighty percent were ascribed to circulatorysystem disease and to malignant abnormalgrowths (neoplasm). Mortality from all ma-lignant neoplasms in the exposed group wasgreater than in the nonexposed group. Can-cers of the digestive and the respiratory sys-tems increased with duration of employ-ment. 87

A further study examined 1,205 men whohad been employed for over 5 years by ShellOil Canada in East Montreal,88{ Their mortali-ty rate was compared with death rates forthe Province of Quebec. The study group wasrelatively small, and only 108 deaths wereobserved. An increased incidence of cancerof the digestive system (SMR of 117) was notstatistically significant, and there was noevidence of excessive lung cancer (SMR of35.4). An excess of brain cancer was foundamong those who had been exposed less than20 years, but it caused only three of thedeaths.

Societal Hazards

Air pollutants include particulate, gases,and trace-metal vapors. Particulate whichcontain absorbed PAH can be carcinogenic.The sulfur and nitrogen-containing emissionsare respiratory irritants. Among the sulfur-containing pollutants, the effects of acidsulfates, sulfuric acid, and S02 dissolved inaerosols are the best documented. All threeare irritants and can make breathing diffi-cult. In addition, some epidemiological evi-dence relates chronic bronchitis and respira-tory diseases to SO2 and to particulate con-

. — —— —— ————. .


centrations in the air. Oxides of sulfur and ni-trogen, transported from industrial areas,may cause acidic rainfall that may reduce theproductivity of forest vegetation and kill fishby increasing the acidity of lakes andstreams. NOX oxides can react with HC in theatmosphere to produce O3, photochemicalsmog, and acid rain. Airborne NH3 may causeheadaches, sore throats, eye irritations,coughing, and nausea in humans.

Among the trace elements that may beemitted, mercury, lead, cadmium, arsenic,and selenium are considered to be potentialair and water pollutants. Arsenic is a car-cinogen, which when inhaled or ingested inlarge amounts, may also cause peripheralvascular disease and neuropathy. * Mercuryis a special problem because its vapors canpollute the air and earth many miles from theplantsite. It can also contaminate surfacestreams and ground water aquifers. It canenter the food chain through the actions ofmicro-organisms, and can also pose a risk ofirreversible neurological damage to humanswho eat fish that have been contaminated bymercury in streams.

Leachates from aboveground disposalareas and burned-out in situ retorts also posepotential problems. PAHs, salts, and metalsmay dissolve in surface streams and groundwater and infiltrate public drinking watersupplies. Water-soluble salts in spent shalecontain as much as 40 percent of the totalbenzene-soluble organic matter. All of thesematerials can be dissolved in water and dis-persed through soils. The exact nature of thethreat posed by these materials to humanhealth is unknown since, for example, PAHsare found throughout nature. However, thePAH content of spent shale leachates (up to100 to 1,000 times higher than is found in nor-mal ground or surface water) is a matter forconcern. Fluoride, if released in excessiveamounts in contaminated water, may causefluorosis (reduced bone strength and debilita-tion) and mottle tooth enamel.

*Neuropathy refers to pathological changes in theperipheral nervous system.

The severity of these hazards will dependon many factors. Many of the risks could bevery small if they are anticipated, and if ap-propriate control strategies are designed andfollowed. If caution is not employed, or ifthere are catastrophic failures in the controlsystems during or after plant operation, dam-age could be severe and long lasting.

Summary of Hazards and Their Severity

The safety and health hazards that mightbe associated with oil shale mining, retorting,and refining are identified in figure 62. Theyare ranked according to their known poten-tial to cause injury or death. As shown, min-ing has the highest potential for accidents,due to risks from rockfalls, explosions, mov-ing equipment, and general working condi-tions. There were two fatalities during themining of over 2 million tons of shale and theproduction of over 500,000 bbl of shale oil.The accident rate has been one-fifth that forall mining, and much lower than that for coalmining. However, this record was achieved insmall-scale experimental mines that em-ployed, for the most part, experienced hard-rock miners. Whether safety risks will in-crease or decrease as mining activities areexpanded cannot be predicted. Risks mightincrease as the work force expands to includeinexperienced miners and as large, rapidlymoving mining equipment is used. On theother hand, the large mines proposed for oilshale plants may reduce risks because of theadditional room in which to maneuver ma-chines.

Fires and explosions are also identified asa hazard in mining. Although no severe fireshave occurred to date, laboratory studies in-dicate that airborne shale dust can propagatea methane explosion. Methane has beenfound in low concentrations in some oil shaledeposits, especially those in the saline zone ofthe Piceance basin. Oil shale dust is, how-ever, far less explosive than coal dust.

Dust is a major health hazard. Its effect onthe respiratory system is well-known. Exces-sive noise is also a recognized hazard. Cancer


Figure 62.—Summary of Occupational Hazards Associated With Oil Shale Development

Relat ive Ranking

Occupat ional Risks Potential Effect Mining

Accidents Injury or death

Retort ing Refining

A

mnnFires andexplosions

Injury or death

Hearing loss orneurological damage

Lung disease

Noise

D u s t

D u s t D e r m a t i t i s

vChemica lE x p o s u r e Cancer

I IChemica lE x p o s u r e

Dermatit is [ 1 I

I I IChemica lE x p o s u r e Poisoning

4.

Chemica lE x p o s u r e

Irritant gases

KEY:

- Higher level of risk

D Medium level of nsk

a Lower level of nsk

SOURCE Off Ice of Technology Assessment


from oil shale mining has not been identifiedas a major hazard. Although the carcinoge-nicity of oil shale dusts and crude shale oilhas been demonstrated by some invesigators,insufficient information and the conflictingresults of other studies prevent a determina-tion of the severity of the risk. However, theincidence of diseases in other industries in-dicates that exposure to these materialscould be hazardous. Worker health should becarefully monitored if health damage is to beavoided, and prevention techniques im-proved, as the oil shale industry develops.

Retorting is regarded as having mediumrisks in all areas. This ranking primarilyreflects the low level of knowledge aboutretorting and its health and safety effects.However, the large variety of substances thatwill be encountered in retorting (from rawshale dust to trace-element emissions) maypose as yet undetected health hazards. Ofspecial concern is the possibility of car-cinogens in shale oil and its derivatives.Possible synergisms in MIS operations (whichcombine mining with retorting) could in-crease the level of risk.

In contrast, shale oil refining is regardedas posing no special hazards in many areasand only moderate risks in the others. This isbecause most of the problems that will beassociated with shale oil processing shouldbe similar to those experienced in convention-al petroleum refining.

Federal Laws, Standards,and Regulations

This section discusses the Federal lawsand standards applicable to oil shale occupa-tional health and safety, and some aspects ofenvironmental health. Other laws which gov-ern specific impacts on air, water, and landare discussed elsewhere in this chapter.

Occupational Safety and Health Act of 1970

This Act was passed to assure every work-ing person “safe and healthful working condi-tions;” it established the Occupational Safety

and Health Administration (OSHA) under theDepartment of Labor. Most OSHA standardspromulgated under the Act pertain to safety,e.g., walking and working surfaces, fire pro-tection, and personal protective equipment.In addition, health standards have been pro-mulgated to limit worker exposure to hazard-ous chemicals and physical hazards, such asnoise and crystalline silica.

OSHA recently published a policy for theidentification, classification, and regulationof toxic substances posing occupational car-cinogenic risks. Under this policy, a sub-stance shown to cause cancer in two animalstudies can be classified as a “category I“carcinogen and regulated to control workerexposure to the lowest feasible levels.Whether any two of the positive carcinoge-nicity results mentioned in table 66 are suffi-cient to cause a category I classificationawaits NIOSH review.

The Federal Mine Safety and HealthAmendments of 1977 (FMSHA)

These amendments apply to all metal andnonmetal mines. They prescribe health andsafety standards “for the purpose of the pro-tection of life, the promotion of health andsafety, and the prevention of accidents. ”FMSHA established the Mine Safety andHealth Administration (MSHA) in the Depart-ment of Labor, and directed the Secretary ofLabor to develop, promulgate, revise, and en-force health and safety standards for work-ers engaged in underground and surface min-eral mining, related operations, and prepara-tion and milling. In addition, each mine oper-ator is to have a mandatory health and safetytraining program. FMSHA also authorizedthe Secretary of Labor to require frequent in-spections and investigations of mines: at leastfour times a year in the case of undergroundmines, and at least twice a year in surfacemines. Records of mine accidents and expo-sures to toxic substances are to be main-tained by mine operators.

Section 101(a) of FMSHA requires thatstandards on toxic material or harmful physi-


cal agents be set to “most adequately assure. . . (on the basis of the best availableevidence) that no miner will suffer materialimpairment of health or functional capacity(even if such miner has regular exposure tothe hazards dealt with by such standard forthe period of his working life). ” NIOSH hasthe responsibility to determine when the ma-terial or agents are toxic at the concentra-tions found in the mine.

Warning labels, protective equipment, andcontrol procedures are to be employed “toassure the maximum protection of miners. ”Medical examinations and tests, where ap-propriate, are to be provided at the opera-tor’s expense to determine whether a miner’shealth is adversely affected by exposures.

Memorandum of Understanding BetweenOSHA and MSHA

Because of the overlapping jurisdiction be-tween OSHA and MSHA, an interagencyagreement was executed on March 29, 1979,to allocate the responsibilities for miningsafety between the two agencies. The agree-ment established that as a general policy, un-safe and unhealthful working conditions onminesites and in milling operations wouldcome under the jurisdiction of MSHA. Wherethese do not apply, or where no MSHA stand-ards exist for particular working conditions,OSHA and its regulations would apply.Where uncertainties arise about jurisdiction,the appropriate MSHA District Manager andOSHA Regional Administrator (or the respec-tive State designees in those States with ap-proved mine-safety plans) shall attempt toresolve the matter. If they cannot do so, theissue will be referred to the national officesof the two agencies. If the issue cannot beresolved at that level, it will be referred to theSecretary of Labor for a final ruling.

The Toxic Substances Control Actof 1976 (TSCA)

TSCA covers the manufacturing, process-ing, distribution, use, and disposal of chemi-cal substances in commerce. However, it

should be noted that if specific operations areregulated by other laws (e.g., Clean Air Act,Clean Water Act) their authority would prob-ably take precedence over regulations pro-mulgated under TSCA. TSCA regulationswould be promulgated only when regulationsunder the other Acts failed to remove a haz-ard. Also, chemicals that are not sold in com-merce are considered “R&D substances” andare exempt from some of the requirementsunder the Act.

Under TSCA, EPA must require industry togive notice 90 days prior to beginning themanufacture of any new substance that is notlisted on EPA’s Inventory of Existing Chem-icals. EPA can also require industry to testthe toxicity of chemicals already in commercethat may pose an unreasonable risk to humanhealth or the environment. Shale oil and itsrefined products are included in the inven-tory list and therefore are not subject to pre-market regulations, but testing can be re-quired under other sections of TSCA if theAdministrator of EPA determines such sub-stances may pose an “unreasonable risk” tohealth or the environment.

Control and Mitigation Methods

Some of the oil shale’s health and safetyhazards can be reduced by using the pollutioncontrol technologies described elsewhere inthis chapter. Others will require specific in-dustrial hygiene controls. The three majorcontrol methods are:

●

●

●

worker training programs, including anintensive training program for new work-ers and refresher courses for workersthroughout their careers;the design and maintenance of safeworking environments; andhealth monitoring programs, includingexaminations and recordkeeping.

Initial training programs and refreshercourses are required by OSHA and MSHA.These agencies also promulgate standardsfor working environments. Health inspectionsare sometimes included in OSHA/MSHA rou-tine inspections, and special health inspec-


tions can be made if the agencies determinethat a serious health hazard exists. At pres-ent, exchange of worker-health informationamong companies is not required, althoughsome companies, especially in the coal miningindustry, have organized such programs toprovide data regarding occurrences of blacklung among miners who change jobs withinthe industry.

Summary of Issues and R&D Needs

Issues

The effect of the scale of operation of fu-ture oil shale facilities on worker safety isstill unknown. As indicated previously, the oilshale industry to date has a good safety rec-ord. It is not clear whether or not this recordcan be maintained in large facilities and in alarge industry.

The protection of worker health and safetyin an industry that is developing with greatspeed is also a major concern. To prevent un-due risks, it is important that the health haz-ards of oil shale and its related materials beidentified, and that appropriate measures beemployed for their control.

R&D Needs

Research is needed in the following areasin order to improve the understanding of thepotential effects of oil shale development onthe workers and on the public:

●

●

additional data gathering and analysisare needed on the health effects of par-ticulate generated during oil shale min-ing and processing. Studies should in-clude: a) identification of absorbedPAHs; b) determination of particulatesize distributions; c) evaluation of therisk of fibrogenicity and carcinogenicity;d) ranking of the unit operations in termsof their degree of risk; and e) determina-tion of their health effects on nearbycommunities with respect to, for exam-ple, chronic bronchitis;characterization of worker exposure toPAHs, other chemical hazards, and

●

●

●

●

A

physical agents such as ionizing radia-tion, heat, and noise stress;evaluation of devices for controllingworker exposure, such as hermeticseals, ventilation equipment, and per-sonal protective equipment;environmental monitoring to determineambient levels of PAHs, trace elements,and other potentially harmful sub-stances;determination of the pathways followedby PAHs, salts, toxic trace elements, andother substances; andadditional controlled animal experi-ments to determine the toxicity, muta-genicity, and other characteristics of theraw materials and products encoun-tered in oil shale processing, and evalua-tion of their synergistic interrelation-ships.

mechanism that would aid in all of thesestudies, and in other ones that evolve as theindustry is created, would be an oil shalehealth registry or central repository for thehealth records of oil shale workers. Thesedata would aid in the statistical work neededto detect extraordinary health trends amongthe workers. These, in turn, could be relatedto working conditions and used to improvepreventive and protective measures.

Current R&D Programs

The following is a partial listing of thehealth and safety R&D projects now under-way both in the private sector and by Govern-ment agencies.

●

●

●

Tosco is studying the fire and explosionpotential of oil shale mining and process-ing.The American Petroleum Institute isstudying the effects of oil shale on fe-tuses by exposing pregnant rats to rawand spent shale dust and shale oil.EPA is performing or contracting workthrough 10 of its laboratories to supportthe regulatory goals of the agency and toensure that an oil shale industry will bedeveloped in an environmentally accept-


able manner. The EPA Cincinnati labo-ratory is studying the handling of rawshale and the disposal of spent shale. Airpollution, wastewater characteristics,and water treatment methods are alsobeing studied and evaluated. The LasVegas laboratory is attempting to designand implement an optimal wastewatertreatment system. The Athens, Ga., labo-ratory is characterizing retort effluentsand developing instrumentation and con-trol systems. Biological and health ef-fects studies are being conducted at theGulf Breeze and Duluth laboratories;these are designed to determine path-ways by which HC enters the food chain,to characterize the aquatic life in the oilshale region before oil shale develop-ment occurs, and to determine the car-cinogenic, mutagenic, and fetal effectsof oil shale and its derivatives andwastes. EPA is also preparing pollutioncontrol guidance documents for the oilshale industry.

DOE is conducting source characteriza-tion studies to determine emissions prop-erties and their health effects. Includedis an extensive program for sampling re-tort liquids, solid products, and wastes.Streams to be sampled include mine ventgases, mine air, retort water, raw andretorted shale, process water, and par-ticulate, Biological testing will be con-ducted to include short- and long-termanimal exposure tests and medical andepidemiological studies of oil shale work-ers.

● The U.S. Department of Agriculture issponsoring work related to the socialconsequences of oil shale developmentand the revegetation of solid waste dis-posal areas.

● The National Science Foundation issponsoring projects to characterize thecontaminants in spent shale and to de-velop techniques for managing them.

Policy Considerations

The major issue surrounding the healthand safety aspects of oil shale development isthe paucity of information on the nature andseverity of the health effects of oil shale, itsderivatives, waste products, and emissions.The effect of the scale of operation of oilshale facilities on worker safety is also un-known. Policy options for addressing theseissues follow,

Inadequate Information

Additional study is needed to determine theeffects on human health of the various chemi-cal substances and particulate encounteredduring the mining and processing of oil shaleand its products and wastes. Such informa-tion would be useful in identifying and miti-gating long-term health effects on workersand the public. It would also be useful in set-ting new standards for worker health andsafety. Options for increasing the amount ofinformation include expanding existing R&Dprograms; coordinating R&D work by Federalagencies; increasing appropriations to agen-cies to accelerate their health effects studies:and passing new legislation specifically call-ing for study of the health and safety aspectsof oil shale development. Methods for imple-menting these options are similar to those de-scribed in the air quality section of thischapter.

Health Surveillance

Collection and maintenance of oil shaleworkers’ health records in a health registrywould facilitate hazard identification andplanning to reduce risks. The registry mightbe located in a regional medical center, withor without Federal agency input. Fundingcould be provided by Government, labor, orthe oil shale developers, or by a cost-sharingarrangement between these groups. The reg-

...


istry location could be the focus of regularmeetings to exchange health and safety in-formation and to disseminate basic scientificfindings that apply to the oil shale industry.

Exposure Standards

As information about chemical health haz-ards is developed and analyzed, NIOSH andMSHA should determine whether exposure

standards are necessary to protect workerhealth and safety. In addition, sampling meth-ods should he in place to monitor exposures.

Worker-Education Campaigns

Worker education is already a part of themining industry. Information about newlyidentified risks should be conveyed to work-ers as soon as possible.

Land ReclamationIntroduction

An oil shale industry will use land for ac-cess to sites, for facilities, for mining, for re-torting, for oil upgrading, and for waste dis-posal. The extent to which development willaffect the land on and near a given tract willbe determined by the location of the tract; thescale, type, and combination of mining andprocessing technologies used; and the dura-tion of the operations. Comparatively littleland will be disturbed by the retorts and up-grading facilities themselves, but much largerareas will be disrupted by mining activitiesand waste disposal operations, particularly ifthe deposits are developed by open pit miningin conjunction with aboveground retorting,which produces retorted shale as a processwaste.

It has been estimated that a l-million-bbl/dindustry using aboveground retorts wouldprocess approximately 600 million tons ofraw oil shale per year, and would require thedisposal of approximately 10 billion ft3 ofcompacted spent shale. Less of the surfacewould be disturbed by in situ retorting, al-though the surface would nevertheless be dis-turbed by drill pads. However, the disturb-ance would be different and less drastic thanfrom an open pit operation. At the same time,the amount of subsurface disturbance for agiven level of oil production would be in-creased because, although with an in situprocess relatively little oil shale is mined, oilrecovery rates are lower and some leaner oilshales would be retorted. Subsurface disrup-

tion from underground mining and in situ de-velopment could affect aboveground condi-tions through subsidence in the mined-outareas. But this might not happen until longafter operations at the site have ceased.

Oil shale plants must be built to complywith the laws and regulations that governland reclamation and waste disposal, Never-theless, there will still be effects on the topog-raphy (ultimately the terrain could be modi-fied to a landscape unlike the original) and onwildlife (through changes in forage plantsand habitats). In addition, unless appropriatecontrol methods are developed and applied,as required by law, the large quantities ofraw and retorted shale could pollute the airwith fugitive dust and the water with bothrunoff and the effluent that has percolatedthrough raw shale storage piles and wastedisposal areas. Solid wastes such as cata-lysts, water treatment sludges, and refinerycoke, will be produced in relatively smallamounts, but will contain toxic componentsthat could degrade water quality unless prop-erly controlled. Similar care will be needed toremove, store, dispose, and revegetate thelarge amounts of overburden that will behandled in open pit mining operations.

Several avoidance and mitigation strate-gies have been proposed to minimize the over-all land impacts of oil shale development. Oilshale plants, access corridors, and disposalareas could be sited to avoid esthetic deteri-oration and improve the feasibility of landreclamation and revegetation programs; and


mining and in situ retorting could be designedto decrease surface subsidence or reduce itsrate. In addition, most development planspropose to protect existing wildlife habitatsand migration routes, where possible, and toenhance the characterist ics of adjacentareas to promote wildlife readjustment. Rec-lamation and revegetation techniques havebeen developed and tested on a small scaleover limited periods of time for abovegroundsolid waste disposal, and backfilling mineshas been suggested to reduce the quantity ofsolid material that must be disposed of on thesurface.

As with air and water control methods, anumber of uncertainties surround the feasi-bility of methods for minimizing land disturb-ance and its effects on wildlife. At issue arethe feasibility of land restoration and revege-tation techniques, and the adequacy of strat-egies to control the leaching of solid wasteand raw shale piles. The methods for dispos-ing of solid wastes by backfilling mines andfor controlling leachates from solid waste dis-posal piles and underground retorts were dis-cussed previously in the water quality sec-tion. In this section the reclamation and re-vegetation of processed shales on the surfaceare examined.

Reasons for Reclamation

The primary purpose of reclaiming the sol-id wastes is to reduce their detrimental ef-fects. These include: changes in the land-scape, the disruption of existing land uses,the loss of the biological productivity on agiven land surface, and the degradation of airand water quality by erosion and leaching. Inaddition, secondary impacts such as fugitivedust would affect not only the immediate areabut adjacent areas as well.

Regulations Governing Land Reclamation

In order to ensure that mining operationswill incorporate reclamation concepts andminimize adverse effects, legislation has beenpassed and regulations have been promul-

gated governing oil shale mining, processing,and waste disposal,

Each State in the oil shale region has rec-lamation laws that apply to all mining opera-tions. USGS has regulations that control oilshale operations only on Federal lands. In ad-dition, the Department of the Interior (DOI)established environmental stipulations gov-erning lands under the Prototype Oil ShaleLeasing Program that include additional spe-cific reclamation standards. The SurfaceMining Control and Reclamation Act(SMCRA), passed in 1977, provides a systemof comprehensive planning and decisionmak-ing needed to manage land disturbed by de-velopment. However, the Act applies only tocoal, and the detailed reclamation standardspromulgated under it may not be appropriateto oil shale in all cases. However, it providesa guide to measure the strictness of otherlaws applicable to oil shale for matters thatare not specific to coal.

The Colorado Mined Land Reclamation Actis administered by a board and division with-in the Department of Natural Resources. Itrequires permits for each mine operation,stipulates application procedures and crite-ria for permit approval, requires surety (e.g.,performance bonds), and sets procedures forenforcement and administration. The Act’sperformance standards are similar in con-cept to those established by the Federal CoalAct. They are not, however, as detailed sincethey must apply to all minerals from oil shaleto sand and gravel (except for coal, which hasbeen amended to correspond to the new Fed-eral requirements); and, in some cases, theyare not so strict. For example, an operatormay choose the postmining use of affectedland; whereas, the Federal standard requiresapproval of such use by the permitting au-thority according to strict criteria. Also, anoperator may substitute other lands to be re-vegetated if toxic or acid-forming materialswill prevent their successful vegetation, andthe mitigation of such conditions is not feasi-ble. Mining would probably be prohibitedunder similar conditions by Federal stand-ards, if they were applicable to oil shale.

63-898 L - 80 - 22


The Utah Mined Land Reclamation Act isadministered by the Board of Oil, Gas, andMining. It provides for various powers of theboard, administrative procedures, surety,and enforcement. However, the Utah law onlyestablishes general reclamation goals anddoes not set detailed environmental perform-ance standards as do SMCRA and the Colora-do law. These goals include minimizing envi-ronmental degradation or “future hazards topublic safety and welfare” and establishing“a stable ecological condition comparablewith . . . land uses. ” They are open to broaddiscretionary interpretation by the Oil, Gas,and Mining Board.

The Federal standards that do apply to oilshale are limited to Federal lands;* they donot govern operations on private land, andare in no way comparable to the detailedstandards that apply to coal under SMCRA.For example, 30 CFR 231.4 establishes verygeneral goals requiring reclamation to“avoid, minimize or repair” environmentaldamage. Specific details must be set by site-specific leases. It is not applicable to true insitu oil shale methods using boreholes andwells, thus will not govern spent shale leach-ing for this technology. Part 23 of title 43authorizes, but does not require, the Bureauof Land Management (BLM) District Manag-ers to formulate reclamation requirementsand USGS Mining Supervisors to set stand-ards for mine plans.

More important are specific lease stipula-tions. Environmental stipulations have beenincluded in the Prototype Oil Shale Leasesgoverning operations on current Federallease tracts. The reclamation and revegeta-tion performance standards that are includedtake into account the experimental nature ofthe program. For example, lessees are given10 years to demonstrate a necessary revege-tation technology; however, operations mustcease if such technology is not developed. Thelease and the environmental stipulations areadministered under the broad discretion ofthe Area Oil Shale Supervisor, who has re-

*About 70 percent of the oil shale land, containing about 80percent of the resources, is federally owned.

quired “best available control technologies”to minimize all environmental damage.

In summary, while reclamation is requiredunder State laws, there are no performancestandards specific to oil shale. Regulationsvary and are not so strict as the general re-quirements of the Federal coal law. There areadditional requirements that pertain to Fed-eral leases.

Reclamation Approaches

Several reclamation approaches can beused to reduce the deleterious effects associated with the disposal of spent oil shale.These include returning surface wastes tomined-out areas; the chemical, physical, orvegetative stabilization of processed shale;and combinations of these approaches.

Reducing Surface Wastes

Mine backfilling was discussed in the sec-tion on water quality. As was indicated, thedisposal of wastes underground will be moreexpensive than surface disposal, but therecould be less surface subsidence caused bythe collapse of overburden materials abovethe mined-out rooms.

Chemical or Physical Stabilization

One approach that can be used to reduceerosion on disposal sites is to use chemical orphysical methods to stabilize the processedshale. Chemical stabilization may be shortterm—from a few months to a couple ofyears—or longer term. Short-term methodsconsist of spraying biodegradable chemicalson the surface; these reduce wind and watererosion by binding particles together. Suchchemicals have been used along with revege-tation to achieve temporary stability.89 T h echemicals do not appear to inhibit seed germi-nation; however, they are expensive and, atbest, temporary.

Longer term stabilization consists of add-ing materials such as emulsified asphalt orprocessed limestone to induce chemical reac-


tions that harden the mixtures. Hardeningcan be accomplished by wetting of shalesprocessed at high temperatures, followed bycompaction. The hardened products have theadvantages of relatively high resistance toerosion and reduced leaching of soluble saltsinto the ground water. Their disadvantagesare that they are esthetically unattractiveand cannot support vegetation unless coveredby a suitable plant growth medium. The long-term effects of chemical stabilization are atpresent unknown.

Erosion can be reduced physically by cov-ering the processed shale with a layer ofrocky material . L ike the chemica l ap -proaches, physical methods inhibit the estab-lishment of a vegetative cover, are not esthet-

ically pleasing, and restrict the future uses ofthe land.

Vegetative StabilizationVegetation offers the most esthetically

pleasing and productive means of stabilizingwaste materials. It also allows for multipleland use. In addition, vegetation theoreticallyoffers a means of continually adapting to thechanging environmental conditions that arelikely to occur on the disposal site over time.

Vegetation will also reduce the overlandflow of water and sedimentation during in-tense storms by increasing the permeabilityof the soil. This will increase the infiltrationof water, thus reducing surface water andpollution and flood hazards. Vegetative cover

P h o t o credit OTA staff

A variety of plant life will be required for revegetation of spent shale areas


will tend to ameliorate micro-climatic condi-tions and also reduce wind erosion and ex-tremes in soil temperatures.

Combinations of Stabilization Methods

Perhaps the most effective means of sta-bilizing waste piles will be combinations ofapproaches such as hardening the processedshales by chemical means and then establish-ing vegetation on a friable soilcover atop thesolidified wastes. The vegetative stabilizationof soil-covered spent shale appears to be thepreferred reclamation approach because thechemical and physical properties of proc-essed shale make it much less amenable tosupporting plant growth that resembles thediversity and density of the present naturalvegetation ecosystems.

The Physical and ChemicalCharacteristics of Processed Shale

The physical and chemical characteristicsof the processed shale are determined by thesource of the raw shale; its particle size aftercrushing; and the retorting parameters suchas temperature, flow rate, and carbonate de-composition, which vary with different retort-ing processes.

The characteristics of processed shalestha t make them undes i rab le a s a p lan tgrowth media are:

● small particle size (texture), which en-courages erosion; and compaction or ce-mentation, which results in low permea-bility to water and poor root penetration;

● high pH (i. e., high alkalinity), which dis-courages plant growth by making essen-tial nutrients insoluble and therefore un-available;

● high quantities of soluble salts, includingelements toxic to plant growth that in-hibit water and nutrient uptake; and

● the dark colors of some spent shales,which absorb solar radiation thus pro-ducing high temperatures that inhibitseed germination a n d d r y t h e s o i lthrough evapotranspiration.

The characteristics of spent shale fromseveral processes are summarized in table 68and discussed below.

Texture

Raw shale that is finely crushed, as in theTOSCO II process, produces a fine silty spentshale that is highly susceptible to erosion.However, if the shale is coarsely crushed asin the gas combustion processes, a coarse-textured spent shale is produced that is lesssusceptible to erosion. The resistance to wet-

Table 68.–The Chemical and Physical Properties of Processed Shales

ProcessingProcess temperature Color Texture a Salinity b pHTOSCO II ., . . . ., . . . . LOW Black Fine 18 9.1Gas Combustion . . ., ., ., . . High Gray Coarse 14 8.7Paraho

Directly heated. ., ., ., ., High Gray Coarse 7 12,2Indirectly heated . . . . ., . . . Low Black Coarse 10 12,3

Union“A” retort . . . . . . . . . High Gray Coarse 3-4 11,4‘‘B’ retort ., ... ., Low Black Coarse 13 8.5

Lurgl-Ruhrgas ., ., ., . . Low/high Gray Fine/coarse 3-7 11-12

aFl”~.[~Xlu~@ processed Shales are predornlrranlly smaller Ihiln 2 mm while coarse-[ extured processed shales are r)redomlnantly larger than 2 InrnbThe electrical ~OfrdUCtlVltY (rnrnhO/Crn) of a safuraled extract prepared frOrn spent shale Partlclw sfnaller than p mm

SOURCE Planf Resources Inshwie The free/arrrallorI oJProcessed O// Shale, prepared for OTA, January 1980


ting of the spent shale originally produced inthe TOSCO process90 91 has been overcome byintroducing steam in the last step of the proc-ess. Spent shales produced by retorting athigher temperatures have not been reportedas resistant to wetting,

The capacity of spent shales to retainwater is moderate. Infiltration rates on fine-textured spent shale (TOSCO II) range fromnear zero to as high as 3 to 4 cm/hr.92 93 Thosefor uncompacted coarse-textured spent shaleare higher.94 Rates of from 2 to 4 cm/hr will besufficient for the surface runoff to be ab-sorbed from most low-intensity storms but notfrom high-intensity ones that occasionally oc-cur during the summer. Moistening and com-pacting the spent shales may achieve close tozero infiltration rates which could be impor-tant for reducing the leaching of salts into theground water. Compaction is more desirablefor spent shales deep in the pile, beyond theplant rooting zone; uncompacted materialsmay be preferable near the surface directlyunder the topsoil layer.

Erosion Control

Because small particle size encourageserosion, erosion control is needed to preventsediments and toxic elements from enteringthe aquatic ecosystems downstream, or theincrease of dust in the air. Additionally, ero-sion removes the surface layers that encour-age plant growth, which take time to develop.

The steepness of the slopes, their length,the drainage provided, control structures, thedensity of vegetation on the slopes, and thetypes of spoils and soil materials on the sitewill affect the extent of erosion. Mulching,surface manipulation, and the timing of top-soil placement, followed by the immediate es-tablishment of vegetation, will usually reduceerosion rates.95 Flatter or shorter slopes willalso aid in erosion control. The recommendeddesign slope of 4: I (horizontal: vertical) with20-ft benches every 50 ft of vertical rise isconsidered prudent and necessary. A slope of

3:1 was found to be the maximum allowablefor slope stability.”

Water diversion and sediment and drain-age catchments are proposed to collect mate-rials washing off site in order to prevent theirentering the aquatic ecosystem. It is likelythat sediment basins will require long-termmaintenance to prevent their filling up andreleasing toxic substances.

Furrowing, pitting, and gouging are otheruseful methods of surface manipulation. Shal-low furrowing on the contour cuts down onerosion losses. Pitting and gouging not onlycontrol erosion but also act as a moisture col-lector.’” They are particularly useful in dryareas and where vegetation is dependent onsnowmelt. A variation of gouging is accom-plished by using a land imprinting machine.’”On soil-covered processed shales, the depthof the depressions will be determined by thethickness of the soil cover necessary to pre-vent the processed shale from being exposed.

Mulches of various types have been usedboth to establish vegetation and to reduce thetemperature of the soil surface. 99 Hydro-mulch, applied at a rate of 1,500 lb/acre isone that is preferred in some studies. 10’) How-ever, it is expensive and, in some cases, hasbeen reported to provide little beneficial ef-fect on already established stands. ’()’ Acheaper natural mulch applied at a rate of3,000 lb/acre,102 such as native hay or straw,is more likely to be used, but it must be takenfrom a certified weed-free field to prevent in-troducing weedy species. It is uncertain thatsufficient mulch will be available, especiallyweed-free hay, for an oil shale industry of 1million bbl/d within 10 years.

Straw or hay mulches often need to be sta-bilized by the addition of emulsified asphalt(300 gal/acre), ’03 or by crimping into the soil.Rock mulches have been found to be superiorto barley straw with respect to plant survivaland growth. 104 Excelsior type materials, arealso very effective, but they are costly and at-tract rodents. ’05

. .


Cementation

Processed shales retorted at high temper-atures and then moistened harden withinabout 3 days in a reaction similar to thatwhich takes place in cement. 106 The product ofspent shale cementation is still susceptible toweathering, and the reaction generally takesplace deeper in the waste pile where theprocess is accelerated by compaction, heat,and high pressure. If shale hardened by thisprocess were to be exposed by erosion, itmight prove to be impenetrable to moistureand plant roots.

Alkalinity

Processed shales retorted at temperaturesof about 5000 C (900

0 F) are less alkaline (pHsranging from 8 to 9*), than those retorted at750° to 800° C (1,400° to 1,500° F) (pHs of 11to 12). In general, the higher the alkinity of itsleachates, the lower the concentrations ofsoluble salts in the processed shale. At higherpHs many plant nutrients are insoluble, andplants will generally not grow in a strongly al-kaline soil medium.

If processed shales are to be used directlyas a growth medium, their alkalinity must bereduced. This can be done by leaching follow-ing deposition and proper compaction, or byadding costly acids or acid-formers. 107 Expo-sure to the atmosphere over a period of sever-al months to several years will reduce it natu-rally.

Nutrient Deficiencies

Spent shales have been shown to be highlydeficient in the forms of nitrogen and phos-phorous available to plants. 108 Therefore ni-trogen and phosphorus fertilizers need to beadded. These can be applied at any time ofyear but spring fertilization has been recom-mended to prevent burning and to reduce fer-tilizing weedy species. 109 It will probably benecessary to fertilize with nitrogen for sev-eral years until the ecosystem begins to fixand recycle its own nitrogen. 110

*PH is a means of expressing acidily or basicity. It rangesfrom 1, highly acidic through 7, neutral, to 14, highly alkaline.

Another means of assisting plants to sur-vive in nutrient-deficient soils is by inocu-lating them with selected strains of fungi thatproduce mycorrhizae. Mycorrhizae are struc-tures that combine the plant root and a fun-gus to increase the survival and growth ofplants in nutrient-deficient soils by increasingnutrient uptake and resistance to a variety ofstresses.

Free-living soil microbes are expected tobegin recolonization of the disturbed area.They will be valuable in fixing nitrogen fromthe atmosphere and recycling organic forms.How soon this will begin is not known. It isknown, however, that wetting and dryingstored topsoil deteriorates the conditions fa-vorable to such microbes. For this reason,prior to use topsoil should be deeply buried toprevent the wetting and drying that occursnear the surface. 11 1

Plant species used to reclaim spent shalespossibly will require inoculation with mycor-rhizal fungi to enhance their growth and sur-vival. 112 Colonizing species on disturbed landsare often nonmycorrhizal. 113 It has also beenfound that with increasing soil disturbance orthe addition of processed shale, the ability ofthe soil to be infected with mycorrhizal fungidecreases. The most successful revegetationspecies become mychorrhizal only late intheir establishment. There appears to be nosignificant effect of the seed mixture, the fer-,tilizer, the mulch, or irrigation on a soil’s po-tential for mycorrhizal infection following itsdisturbance. 114

Salinity

Because spent shales are often quite salty,they present major problems for establishingvegetation, and for the water quality fromsurface runoff or drainage through them. 115-120

High concentrations of salt in the soil mediarestrict water and nutrient uptake. * Thesecan only be lowered by leaching with supple-mental water.

*Electrical conductivity is a measure of a soil’s salinity. Aconductivity of 4 mmho/cm is considered saline, and above 12mmho/cm, highly saline.


Leaching

Depending on the characteristics of thespent shales, about 5 acre-ft of water peracre will be needed for leaching and plantgrowth. 122 This is based on a net requirementof 48 inches of leaching water and an 80-per-cent irrigation efficiency. The actual supple-mental water needed will vary with annualprecipitation, evaluation, and aspect, To en-sure adequate infiltration and to prevent ero-sion, it should be continually applied at lowrates (e. g., 2 to 3 cm/hr) and in a spray form.Leaching will probably not be uniform overthe entire surface, therefore surface monitor-ing and additional localized leaching may beneeded.

Toxicity

High concentrations of boron in spent shalecan be toxic to plants. On the other hand, theelements molybdenum, selenium, arsenic,and fluorine (also found in shale) are general-ly not toxic to plants. However, when theseelements are taken up by plants, they can be-come toxic to grazing animals. Susceptibilityto such toxicity varies among animal speciesas well as within a species. It is dependent onthe concentration of the elements within theplant, the size of the animal, its daily diet, andits general physiological condition. The condi-tions that encourage the uptake of these ele-ments by plants, and their resulting toxicityin animals are complicated and poorly under-stood. Proper management should help toavoid or alleviate the problems with livestock.This can be achieved by restricting livestockgrazing to seasons when the elements arepresent at low concentration in the plants, byvarying the mix of plant species to be used inthe grazing areas, and by feeding seques-tering supplements to reduce the toxicity ofthe elements. The management of wildlife,however, is very difficult and problems willpersist in this realm.

The dominant soluble ions in spent shaleare sodium and sulfate, with abundant calci-um, magnesium, and bicarbonate also pres-ent. Of the trace elements identified in proc-

essed shale leachates, selenium and arsenicare not cause for concern, but fluorine,boron, and molybdenum are more serious. ’z]Plants grown on processed oil shales and soil-covered processed shales in northwesternColorado have been found higher in molyb-denum and boron than plants grown in ordi-nary soil, although their selenium, arsenic,and fluorine contents were moderate. 124

Excessive Heat

The color of the processed shale reflectsthe amount of residual carbon on the retortedparticles. Black and gray processed shalesare produced by low- and high-temperatureprocesses, respectively. The color influencesthe surface temperatures of the plant growthmedia which, in turn, affects seed germina-tion and the plant-water relationship. Thedark-colored material warms up earlier inthe spring, inhibits seed germination more,and creates drier soils than does lighter col-ored processed shale. Temperatures of up to78° C (196° F) have been reported for theTOSCO II material. 125 126 The color can bemodified to a certain extent by the use of sur-face mulches or a covering of topsoil-like ma-terial, which reduces many of the salinity andalkalinity problems as well as the need forsupplemental water.

Another temperature problem encounteredin the massive disposal of spent shales is thatthe processed shales will probably go into thedisposal pile at temperatures in excess of 40”C (98° F). This will create a heat reservoir, Itis not known how long it will take to cool, If aspent shale pile is warmer than normal soilswithin the area, the site would be drier thanexpected because of the increased potentialfor evapotranspiration.

Use of Topsoil as a Spent Shale Cover

An alternative to revegetating directly onspent shale is the establishment of vegetationon a cover of topsoil or topsoil-like over-burden material placed over the spent shale.Such a soil cover offers several advantages.

— —

336 ● An Assessment of 0il Shale Technologies

Because it does not have the problems of highsalinity and alkalinity, no supplemental wateris required for leaching. The material is amore suitable medium for plant growth be-cause it has greater water-holding capacity,more nutrients, and promotes a more intimaterelation with plant roots.

Economics and a possible lack of longevityare the primary disadvantages of using a soilcover. Additional costs would be incurred forsegregating suitable materials from thosewith undesirable properties, for transportingand storing materials, and for surfacing overthe spent shales. In time, the natural geologi-cal process of erosion may eventually cutthrough the soil cover and expose the spentshale. An artificial soil profile using over-burden materials between the topsoil and thespent shale would greatly reduce, if not elimi-nate, the problem. With proper managementmost erosion should be localized. However,with improper management such as overgraz-ing, reductions in vegetative cover could oc-cur that would allow larger areas to be ex-posed. If erosion were gradual over a fewhundred years, the vegetation possibly wouldadapt to the thinning soil cover, and naturalleaching and weathering could render thespent shale a more suitable growth medium.Despite these disadvantages, the use of a soilcover will provide for the more rapid estab-lishment of a vegetative cover that will per-sist longer than would vegetation establisheddirectly on spent shale.

The depth of the soil cover needed will varyfrom site to site, but will generally range from1 to several ft in thickness. 127 128 Soil surveysof the Piceance basin indicate that sufficientsoil and soil-like material exists in the dispos-al sites, particularly those with deep alluvialdeposits, and this should provide adequatecover material.

The selection of topsoil or topsoil-like over-burdens will have to be based on chemicaland physical analyses. This is important be-cause the soil types and their toxicities vary.The treatment of the soil cover will be similarto the treatments of soil used for the reclama-tion of surface-mined coal areas, about whichthere is more knowledge.129 Soil surveys of the

basins will also be useful in deciding whatmaterials to use. It is doubtful that the capil-lary rise of salts will be a problem unless soilsare continually exposed to saturated condi-tions. This might happen if improper engi-neering of the disposal site created seeps orallowed pending.

Species Selection and Plant Materials

The selection of plant materials to be usedin reclaiming processed shale is determinedby several factors, the most important ofwhich is species adaptability. Adaptability(suitability) is intimately tied to the ability of aplant to complete its entire lifecycle, and toreproduce itself from year to year over a longperiod. The plant’s growth form, drought re-sistance or tolerance to stress, mineral nutri-tion requirement, and reproduction charac-teristics must all be considered. In addition tobeing adapted to the growth medium, plantsmust also be adapted to local temperatures,elevation, slope, aspect, and wind conditions.They should be able to survive the weeds andanimals that may invade the site. Palatabilityto livestock and wildlife as well as availabili-ty of seed and competition among speciesbeing planted are also important factors.

In addition to the results of actual revege-tation test plots, several information sourcesand guides are available to assist in the selec-tion of species adapted to conditions likely tobe encountered in oil shale reclamation.130-134

These include the Plant Information Networkcomputerized data bank located at ColoradoState University. 135

In general, mixtures of various grasses,forbs, shrubs, and in some cases trees, aredesirable because they offer a greater rangeof adaptation. 136 Mixtures may include spe-cies adapted to each of the different microcli-mates, moisture levels, and soils. The resultsof using a well-planned mixture can be a fast-establishing, long-term cover that is less vul-nerable to pests, disease, drought, and frost.

Recommended mixtures used in test plotsmay include both indigenous (native) and in-


troduced perennial species. In one study, amixture of native and introduced species dis-played the highest productivity and allowedthe least amount of invasions by weeds.’}’ Al-though a mixture of non-native species had ahigher plant density, it also allowed the great-est invasion of weeds. 138 Weeds are undesir-able in that most are annuals (complete theirlifecycle in 1 year) dependent on precipita-tion; they are therefore an unreliable erosioncontrol. They also compete with the more de-sirable perennial species (species that persistfor several years) for water and nutrients.These annuals are expected to disappearwith natural succession over a few years.

Species selection is complex and involves,in addition to considerations of the speciesitself, a tradeoff among many interacting fac-tors. 139 These include: Federal, State, and lo-

cal reclamation requirements; rehabilitationand land use objectives; the nature of the site;the timing of the program; species compatibil-ity; mechanical limitations in planting; seedand seedling availability; maintenance afterplanting; and cost,

Seeds

Planting seed by drilling or broadcasting isa common way of establishing vegetation in areclamation plan. Seed is available commer-cially from collectors and seed companies. ’40While many commonly used seeds are availa-ble from dealers under contract, proceduresfor cultivating wildland plants for seed pro-duction have generally not been developed.Also, certain varieties of the native plantspecies may not be available from commer-cial sources. Until reliable seed productiontechniques are developed (which may requireup to 10 years), seeds for propagating nativeplants will generally have to be collectedfrom wildland populations. This may be aproblem for a large oil shale industry, sinceseed production from wildland populationscan be unpredictable from year to year; somenative species produce abundant seed cropsonly in years when conditions are especiallyfavorable.

Seeding is best done in late fall or earlyspring when soil moisture is high, althoughthe operation of seeding equipment in thespring may be hampered by wet soil condi-tions.’” Seeding rates may vary from 10 to 30lb of pure live seed per acre depending onslope and whether the seed is broadcast ordrilled. Drier exposures and broadcast tech-niques require more seed.

Another problem in propagating plantsfrom seed is dormancy of seed. Extensivetreatment of the seed may be required inorder to overcome it. For these reasons, vege-tative propagation is a necessary alternativeto seed propagation for producing plantingstock of native species.

Containerized Plants

Container-grown plants have been success-fully used in several oil shale revegetationstudies. 142-144 They offer several advantagesover seed: 145

they make efficient use of scarce seed orseeds especially adapted for harsh sites,plant survival and growth are optimizedby rapid root growth into the surround-ing soil,well-developed plants are generally ableto withstand grazing or other stresses,andthey can be inoculated with fungi just be-fore seeding to ensure the developmentof mycorrhizae.

Container-grown plants can be hardened tothe fluctuating and more extreme environ-mental conditions they will encounter at therevegetation site by gradually exposing themto drier conditions and greater temperatureextremes. The higher cost of container-grownstocks is offset by their better survival rate. 146

They are recommended for fall or earlyspring planting on harsh sites where estab-lishment of seeds may be difficult or impossi-ble due to erratic or low precipitation orother environmental stresses. Bare root stockis another alternative, but can only be usedwith sufficient soil moisture to ensure goodroot penetration into the growth medium. 147

——


Timing of Reclamation

Initiation of revegetation efforts will bedelayed during the first 3 to 10 years ofoperation until sufficient waste materialshave been compacted and require furtherstabilization. Disposal will likely begin at oneend of a canyon and fill up in strips ratherthan gradually filling the entire canyon. Thiswill allow early stabilization of narrow stripsof land thereby minimizing the size of activedisturbance.

Once revegetation begins, reclamationneeds will gradually increase as portions ofdisposal sites are prepared for planting. Atfull production, reclamation needs would de-pend on processing rates and method of dis-posal. (See table 69.)

Complete filling of canyon disposal sitesmay take up to 30 years or more depending onprocessing rates and the sites’ disposal ca-pacities. Early revegetation of narrow stripswill permit the evaluation of reclamationtechniques, and allow for any modificationsthat may be needed during subsequent reveg-etation efforts.

Cost of Reclamation

Estimates of average reclamation costsrange from $4,000 to $l0,000/acre dependingon the site conditions and the land use to beachieved. If disposal is completely on the sur-face, this represents only about 1.4 to 4.4cents/bbl of shale oil for a 50,000-bbl/d oper-ation.

Protection of the Reclaimed Site

The reclaimed areas should be protectedby proper management and monitoring to en-sure that stability is maintained. Protectionwill be needed whenever the vegetation onthe site may be threatened by livestock(including feral horses), wildlife, invadingweeds, or human activity. This can be donelargely by controlling the degree of use.

The impact of livestock use on the erosionof revegetated spent shale is unknown; it ispossible that erosion of the finer processedshales on steep slopes could be substantial.Erosion from livestock use on soil-coveredshales would be less of a problem. This as-

Table 69.–Estimates of Reclamation Needs Under Various Levels of Shale Oil Production

Production level (bbl/day)

50,000 50,000 b 100,000 250,000 1,000,000

Required annual disposal area (acres)c

6 9 8 - 7 9 6 2 7 9 - 3 1 8 — 138-159 344-398 1,378-1,592.Water requirements

(5 acre-ft/acre) 349-398 acre-ft/yr 140-159 acre-ft/yr 690-795 acre-ft/yr 1,720-1,990 acre-ft/yr 6,890-7,960 acre-ftlyrFertilizer

Nitrogen (80 lb/acre) 5,584-6,368 lb/yr 2,232-2,544 lb/yr t 1,040-12,720 lb/yr 27,520-31,840 lb/yr 110,240-127,360 lb/yrPhosphorus (80 lb/acre) 5,584-6,368 lb/yr 2,232-2,544 lb/yr 11,040-12,720 lb/yr 27,520-31,840 lb/yr 110,240-127,360 lb/yr

Seed (30 lb pure Iiveseed/acre) 2,094-2,388 lb 837-954 lb 4,140-4,770 lb 10,320-11,940 lb 41,340-47,760 lb

Containerized plants(300/acre) 20,940-23,880 pits/yr 8,370-9.540 pits/yr 41,400-47,700 pits/yr 103,200-119,400 pits/yr 413,400-477,600 pits/yr

MulchWood fiber ( 1,500

lb/acre) 104,700-119,400 lb/yr 41,850-47,700 lb/yr 207,000-238,500 lb/yr 516,000-597,000 lb/yr 2,067,000-2,388,000 lb/yrstraw (3,000 lb/acre) 209,400-238,800 lb/yr 83,700-95,400 414,000-477,000 lb/yr 1,032,000-1,194,000 lb/yr 4,134,000-4,776,000 lb/yrw/asphalt binder (300

gal/acre) 20,940-23,880 gal/yr 8,370-9,540 gal/yr 41,400-47,700 gal/yr 103,200-119,400 gal/yr 413,400-477,600 gal/yr

aAll numbers are approximate Actual needs will vary with aridity of the she (elevallon, slope, and aspecl) adapled planl Sr)ecles selected and SJrl arnertdrnenls rewedbASSumeS bo.percen! Cllsposal In underground rnlne WorklwsCASSUMeS disposal ~lle 451 meters 11 so ft) deep Acreage esflrnales Were based on Po//uIIorI Conlro/ Gu(darrce for 0// S/ra/e Deve/oprnenl Environmental protection Agency. Clnclnnatl Ohio. JUIY 1978 P

3-68

SOURCE Plant Resources lnshtute The Rec/arna//orr ofl?ocessed 0(/ S/ra/e prepared for OTA January 1980

Ch. 8–Environmenlal Considerations ● 339

pect of postmining land use will require care-ful monitoring. Indirect methods for protect-ing a site against livestock include adding lesspalatable species to the seed mixture, pro-viding salt blocks and permanent water sup-plies away from the seeded areas, controllinglivestock numbers, herding, fencing, and, ifnecessary, repellents. l48

P h o t o credit OTA staff

Reclaimed sites will have to be protected from wildlife

Protection against wildlife will also be re-quired. This includes large herbivores as wellas small burrowing animals such as pocketgophers that can be expected to move into therevegetated area. If not controlled, over-utilization of vegetation may occur and toxiccompounds may be brought to the surface byburrowing animals. 149

Monitoring and subsequent managementmust also ensure that refertilization, seeding,and additional control of erosion or weeds,are provided if necessary, Similarly, monitor-ing plant succession, productivity, and uti-lization should all be included in the reclama-tion management plan. 150

Review of Selected Research to Date

Research undertaken on the topic of oilshale reclamation falls into two categories:

●

●

baseline studies that describe the eco-logical characteristics of the existing en-vironment in the oil shale basins, andcharacterization studies of processedshale and the testing of reclamationmethods.

Data from both types of research are neededin designing, directing, and assessing pastand future reclamation studies.

Baseline Studies

A general description of the vegetation ofthe oil shale basins can be found in chapter 4.Additional descriptions that contribute to thebaseline data are available for Federal landsfrom BLM’s Unit Resource Analysis151 andManagement Framework Plans. 152 More spe-cific vegetation inventories have also beenmade for site-specific areas within thesebasins such as transmission and pipeline cor-ridors, Land classification systems have alsobeen developed for the piceance basin,153 154

Eighteen phyto-edaphic units (plant-soil units)were identified. 155 The description of eachunit provides information on soil, vegetation,climate, aspect, and landform interpretationsand hazards of land use. A section on rec-lamation considerations is provided to iden-tify the most hazardous characteristics of theunit (e. g., the potential for erosion and slump-ing) that need special attention and care, par-ticularly after disturbance as a result of oilshale development. Management recommen-dations and alternatives are supplied to over-come the identified limitations.

Other information on plant community re-lationships (phytosociology) is currently beinggathered by Colorado State University for thePiceance basin. This will help the land man-agers and reclamation specialists to selectthe proper species to be used in reclamation.Such studies are lacking for the basins inWyoming and Utah, and few physiologicalstudies have been conducted with existingplant species at the proposed disposal sites orwith plant materials to be used in reclama-tion to determine their tolerance limits to thevarious adverse conditions likely to be en-


countered. Little is known about the naturalgenetic differences that exist in native plantcommunities. These might make the plantsmore or less adaptable to adverse environ-mental conditions encountered in oil shalereclamation.

Reclamation Studies

Investigations to determine the manage-ment needed to produce conditions favorableto the establishment and growth of plants onprocessed shales were initiated by private in-dustry in the mid-1960 ’s. ’5’ These were basedon previous knowledge developed by rangemanagers, biologists, and numerous arid andsemiarid studies, as well as other baseline in-formation from the oil shale basins.

Where possible, the sites for reclamationtests have been selected to simulate, as close-ly as possible, the environmental conditionsto be encountered during the reclamation ofdisposal sites used for large-scale production.Sites have been selected in high- and low-rainfall areas, with various combinations ofslope, aspect, and processed shale materials.However, most revegetation experimentshave been hampered by a lack of processedshale. This shortage, coupled with the highcosts of transporting retorted shales to fieldsites (in some cases from as far away asCalifornia), have restricted both the size ofthe test plots (2 to 5,000 ft2), and the type ofprocessed shale evaluated.

To date, field studies using spent oil shalesas plant growth media have centered on theTOSCO II, Union “A” and “B,” and Parahomaterials .157-162 These studies show that withintensive treatments plant growth can be es-tablished directly on spent shales, althoughuse of a soil cover is more successful.

It is difficult to compare the results ofrevegetation studies with the various proc-essed shales because the experimental de-signs varied so widely. Different plant spe-cies were used, and fertilizer, mulch, slope,aspect, and soil cover also varied. Most of theearly (1965 to 1973) revegetation studies forColony used spent shale from the TOSCO II

process. 163 During these studies the basicchemical data needed to design a reclamationprogram were incorporated into greenhouseand small field plots (100 ft2). Revegetationwork on other processed shales, all of whichare coarser, had been confined to Union Oilplots planted in 1966 and Colorado State Uni-versity plots planted in 1973. In the late1960’s and early 1970’s, larger field plots(41,000 ft2) were built using many of the resultsof the earlier experiments, including the ef-fects of soil supplements such as fertilizerand organic matter.

Since the early 1970’s, studies have beenconducted on disturbed soils without proc-essed shales to determine the establishmentof plant species, microbial activity, and long-term successional trends. These studies wereencouraged by the finding that the revegeta-tion of soil-covered processed shales wasmore successful than revegetation directly onprocessed shales. This was because the soilcover does not have the adverse chemical andphysical properties of processed shale thatinhibit plant growth.

Supplemental water has been used to es-tablish plants in most of the processed shalerevegetation studies. The addition of 10 to13 inches of water during the first growingseason with no subsequent irrigation hasresulted in the establishment of a vegeta-tive stand and the persistence of adaptedspecies for several years. The salt leachingrequirement (5 acre-ft of water per acre) is inaddition to this supplemental water. Onlylimited success in seeding and transplantinginto spent shale without supplementary wa-ter has been reported. 164 However, establish-ment without supplemental water might beachieved by mulching with straw or hay andallowing salts to be leached by natural pre-cipitation prior to seeding or planting, al-though the time period required for this couldbe unreasonable. Micro-watersheds consist-ing of low-level diversion b a r r i e r s o rmounded spent shale have also been pro-posed and initiated to concentrate water forplant growth.165


Several researchers have worked on theproblems of leaching soluble salts from theprocessed shales and the surface stability ofseveral retorted shales including TOSCOI I .166-172 It appears unlikely that salts willmigrate to the surface by capillary rise inmost areas of low precipitation. Only in areaswhere soils were saturated by supplementalwater was there temporary desalinization ofsurface layers. When the supplemental wa-ter was discontinued, surface salinity beganto drop due to leaching from natural precip-itation. From these studies a better under-standing has developed of solutions to theproblem of establishing a self-sustainingvegetative cover.

Several studies are continuing, and a newsuccessional study has been initiated 173 t oevaluate the long-term feasibility of usingprocessed shales directly as plant growthmedia and the influence of various depths ofsoil cover over spent shale. It has been set upin the Piceance basin to obtain informationrelated to the reseeding of disturbed areas inorder to reestablish a diverse, functionalecosystem in as short a time as possible.Various seed mixtures, ecotypic varieties ofnative species, microbial activities, seedingtechniques, fertilizer levels, irrigation, andmulching treatments are being evaluated. Inaddition, the rate and direction of plant suc-cession is being monitored to identify signifi-cant trends in vegetation changes, and to de-termine how these trends are influenced bythe various treatments and practices, 174

Few studies have been conducted on rawshale. This is because in the past it has beenassumed that most raw shale of commercialquality will be retorted. Additionally, the rawoil shales are hard and resi l ient . Whenmined, the shale fractures into coarse frag-ments that have extremely low water-holdingcapacities, which renders them undesirablegrowth media. For these reasons, it is likelythat raw shale of noncommercial qualitywould be buried deeper in the disposal pilesand not used as a growth medium,

Summary of Issues and R&D Needs

Research to date has shown that with in-tensive management vegetation can be estab-lished directly on processed oil shales. Theprimary requirements are the leaching ofhigh levels of soluble salts with supplementalwater, the addition of nitrogen and phos-phorus fertilizers, and the use of adaptedplant species. However, the establishment ofvegetation on spent shales covered with atleast 1 ft of soil is preferred because it is lesssusceptible to erosion and does not require asmuch supplemental water and fert i l izer .Adapted plant species are required for eithersoil-covered or spent shales.

The long-term stability and the self-sus-taining character of the vegetation is un-known, but if sufficient topsoil is applied theresults of research on small plots indicatesthat short-term stability of a few decades ap-pears likely. Monitoring and subsequent man-agement must ensure that any necessary re-fertilization, seeding, and erosion and weedcontrol be provided. The reclamation man-agement plan must also include monitoringplant succession, productivity utilization, andthe presence of high concentrations of ele-ments toxic to plants and animals.

Whether or not the revegetation of spentshales is considered successful depends onthe desired land use and the performancestandards applied to measure the success.For example, the reestablishment of vegeta-tion that reduces erosion and is productive,self-sustaining, and compatible with sur-rounding vegetation might be considered suc-cessful for livestock but not for wildlife use.The minimum requirements for vegetationshould be to stabilize the disposal sites so thatthe detrimental effects caused by erosion canbe minimized. Where ecologically feasible,multiple land use of disposal sites should beencouraged.

Reclamation plans will have to be site spe-cific since environmental conditions vary


from site to site. Proper management will berequired in all instances, if only to protectplant communities in surrounding areas fromharm. Proper management is even more im-portant in the reclaimed areas. If the vege-tative cover were completely lost, the nega-tive effects would increase. The conditionswould not be as severe as those without anyreclamation because they would be reducedby restrictions in slope, catchment and diver-sion dams, and other mitigation completed inthe early stages of reclamation.

If revegetation completely failed, produc-tive land use would be severely reduced oreliminated. It is doubtful that, after oncebeing reclaimed, conditions would deterio-rate to the point of eliminating all vegetationfrom a disposal site, although a natural suc-cession of species would occur that wouldfavor those that had superior adaptability tothe harsh conditions. Weedy or unpalatablespecies of less use to livestock and wildlifewould undoubtedly invade the sites.

The types of reclamation needs for a large-scale industry (1 million bbl/d) are similar tothose generated for a small industry (50,000bbl/d), but differ in the amounts of materialsthat will be required and the rates at whichthey must be supplied. It is probable thatshortages of adapted plant materials and as-sociated support materials (such as mulchesand greenhouse facilities) would occur at thehigher production rates. The problem is com-pounded by the fact that demands for plantmaterials are increasing from other miningoperations such as coal and uranium. Theseverity of the shortages will depend onwhether the oil shales are processed in situ orsurface retorted, and whether the processedshales are disposed of underground or on thesurface. Surface reclamation needs will besomewhat less demanding with MIS process-ing or with underground disposal of surface-retorted shales.

Research on the reclamation of processedshales is continuing. Areas of major concernrequiring additional study include:

● the selection and propagation of speciesespecially adapted to conditions likely to

●

●

●

●

●

●

be encountered in the reclamation of thespent shales. This should include theidentification of ecotypic variations,seed production by cultivating adaptedwildland plants, and research to deter-mine species performance under abnor-mal conditions (e.g., drought, salinity,and high temperatures);the role and use of soil microbes andmycorrhizal fungi in soil building andplant growth. Successful reclamationwill depend on developing a protocol toselect and/or maintain the essentialmycorrhizal fungi in disturbed habitatsor to develop methods to reinoculatethese fungi in habitats where they areabsent;the plant succession for large areas of afew hundred acres in size under naturaland disturbed conditions, including theinfluence of animals on revegetated sur-faces;the toxicity of elements such as fluorine,boron, molybdenum, selenium, and arse-nic to plants and grazing animals. A pro-gram to monitor these elements shouldbe established on newly reclaimed areasat least for the first few years;the probable heat retention within thedisposal pile and its effect on reclama-tion timing and revegetation;the rates of erosion on large, reclaimedareas of a few hundred acres in size. In-formation is needed on how much waterruns off the area following snowmelt inthe spring and after high-intensity sum-mer storms, including how much sedi-ment and soluble salts will be containedin the water; andthe viability of vegetation on raw shale,

Policy Options for the Reclamation ofProcessed Oil Shales

For Increasing Available Information

More information is desirable on reclama-tion methods and the selection of proper plantspecies for revegetation programs. Optionsfor obtaining this information include the


evolution of existing R&D programs by theU.S. Department of Agriculture (USDA), EPA,and other agencies; the improved coordina-tion of R&D work by these agencies; increas-ing or redistributing appropriations to accel-erate reclamation and revegetation studies;and the passage of new legislation specifi-cally for evaluating the impacts of land dis-turbance. Mechanisms are similar to thosediscussed in the air quality section of thischapter.

To Develop Reclamation Guidelines for Oil Shale

SMCRA provides for comprehensive plan-ning and decisionmaking to manage disturbedland. However, in general, the reclamationstandards promulgated under the act areonly appropriate for coal, but not necessarilyfor oil shale. Thus, new reclamation guide-lines specifically for oil shale may be desir-able, with standards for postmining land usesthat are ecologically and economically feasi-ble and consistent with public goals. If theAct were amended to encompass oil shale,Congress could direct that reclamation guide-lines be developed by DOI’s Office of SurfaceMining, either alone or in conjunction withother agencies. Alternatively, Congress couldpass new legislation calling for the prep-aration and implementation of reclamationguidelines for oil shale.

To Expand the Production of Seeds andPlant Materials

While many common seeds are availablefrom commercial dealers, procedures for cul-

tivating specific wildland plants for seed pro-duction have generally not been developed.Also, seeds of certain native plant species arenot commercially available.

A shortage of seeds could be a problem fora large oil shale industry. For example, theUSDA’s plant materials centers often requireup to 15 years to identify and developadapted species for release to commercialsuppliers or to industry for trial plantings.Furthermore, the centers intentionally limittheir activities so that they will not competewith commercial producers. Thus, they havenot developed mass production capabilities,nor have they adopted some of the more re-cent propagation technologies (such as micro-propagation, cutting, and fungal and bacteri-al inoculation) that are used commercially. Inorder to meet the future demands of a largeoil shale industry, it may be necessary for thecenters to expand their facilities and prop-agation capabilities. This could be costly interms of facilities, technologies, and person-nel. Policy mechanisms for expanding cooper-ative agreements between the centers andcommercial producers need to be developed.These activities would not only benefit oilshale, but also most other reclamation andarid and semiarid revegetation projects aswell.

PermittingIntroduction the States to determine whether a prospec-

tive facility is able to meet specific require-During the past 10 years an increasingly ments under the law. The operation of an oil

complex permitting system has been devel- shale facility requires well over 100 permitsoped to assist the Federal, State, and local and other regulatory documents from Feder-governments in protecting human health and al, State, and local agencies. They include thewelfare and the environment. Permits are the permits for maintaining the environment andenforcement tool established by Congress and for protecting the health and safety of work-

344 . An Assessment of 0il Shale Technologies

ers, and in addition, those that would beneeded for any industrial or commercial ac-tivity: building code permits, permits for theuse of temporary trailers, sewage disposalpermits, and others. Of these, a few—the ma-jor environmental ones—require substantialcommitments of time and resources. The ma-jor environmental permits that must be ob-tained prior to the operation of an oil shale fa-cilit y are:

●

●

●

●

●

●

●

●

●

●

a PSD permit required under the CleanAir Act;an Air Contaminant Emissions permit re-quired by the State of Colorado;a Special Primary Land Use permit—which is required for plant siting in RioBlanco County;a Mined Land Reclamation permit re-quired by the State of Colorado;an NPDES permit required under theClean Water Act;a section 404 Dredge and Fill permit un-der the Clean Water Act if the operationaffects navigable waters;a Subsurface Disposal permit as re-quired by the State of Colorado if wateris reinfected;a permit for the disposal of solid wastesgenerated by the facility required underRCRA;testing of effects, recordkeeping, report-ing, and conditions for the manufactureand handling of toxic substances as stip-ulated under TSCA; andan EIS as required by the National Envi-ronmental Policy Act-if an oil shale plantinvolves a major Federal action signifi-cantly affecting the environment.

The responsibilities for reviewing and ap-proving applications are distributed amongmany Federal, State, and local agencies. Fed-eral agencies include EPA, the Department ofthe Treasury, DOI (including BLM and USGS),the Department of Defense (e.g., the ArmyCorps of Engineers), and the Interstate Com-merce Commission. State entities in Coloradoinclude the Department of Health, the De-partment of Natural Resources, and the StateEngineer. Because of varied and overlapping

regulations and statutes it has often been dif-ficult to know which agency must be con-tacted, and which permits are required fromwhich entity.

The following discussion examines:●

●

●

●

●

●

how various parties view the permittingprocess;the current status of oil shale developersin obtaining the needed permits;the t ime required for preparing andprocessing permit applications;the disputes encountered so far in ob-taining such permits;the potential difficulties that might beencountered by a developing oil shale in-dustry; andpossible policy responses to permittingissues.

Perceptions of the Permitting Procedure

The various parties interested in environ-mental permits for oil shale facilities havewidely divergent views concerning the effec-tiveness and problems of the permitting pro-cedure. Industry is concerned about thelength of time it takes to obtain permits andthe uncertainty of obtaining them. The envi-ronmental community is watchful of the pro-cedure’s effectiveness in enforcing the law;and the regulators themselves are troubledby their limited personnel and budgetary re-sources.

The high cost of oil shale projects makesunexpected delay costly, and industry is con-cerned with uncertain agency decision sched-ules or with unpredictable litigation that candelay or prevent project construction. Fur-thermore, some regulations and standardshave not yet been set because of a lack of suf-ficient knowledge about the impacts of shaleoperations and the effectiveness of their con-trol. Developers are particularly worriedabout the effects of new regulations (such asfor visibility maintenance as part of the PSDprocess) on process design and project eco-nomics. They are concerned that new regula-tions could necessitate costly retrofits to ex-


isting plants or even the cessation of opera-tions. For facilities under construction, thenew regulatory requirements may mean rede-sign or addition of environmental controlequipment or strategies. These uncertaintiesincrease the risk that a project, once started,may not be completed. Prospective develop-ers also express their frustration over thelengthy and expensive procedures for prepar-ing permit applications (including monitoringand modeling requirements) to meet some en-vironmental statutes. This discontent is some-times compounded by overlapping agencyjurisdictions and by repetitive paperwork.

The environmental community assertsthat, given the complexity of oil shale opera-tions, the extensive application and reviewprocedures are necessary to fully assess envi-ronmental impacts, the effectiveness of con-trol measures, and compliance with environ-mental law. They suggest, in fact, that agencyenforcement of environmental laws is toooften compromised by weak regulations andby a lack of essential information on whichboth to base permitting decisions and to en-force the conditions of the permits. Informed,meaningful public involvement in the process-ing of environmental permits is therefore pro-moted by environmental groups to ensurethat all points of view are represented inagency proceedings. It is particularly impor-tant, these groups hold, that the technicalanalyses on which agency decisions dependare subjected to independent scrutiny. How-ever, they believe that adequate provisions

are seldom made for public participation, andaccess is not provided to the informationneeded to evaluate the applications. Theynote that few agencies have an affirmativepublic involvement process. They find it isoften difficult to follow and monitor agencydecisionmaking.

The regulators feel overwhelmed by the in-creasing number of permits and by the com-plexity of the review. They believe that theirpersonnel and financial resources are toolimited for the present caseloads and certain-ly will be dwarfed by any rapid increase inapplications arising from an expanding ener-gy industry, EPA’s Region VIII, for example,includes not just the oil shale region, but mostof the Western coal and uranium resources.Regulatory personnel also contend that theyare handicapped by inadequate technical in-formation about the technologies that theymust review and assess.

Status of Permits Obtained byOil Shale Developers

The number of permits needed for a givenfacility depends on its site; on whether it in-volves Federal land; on the scale, type, andcombination of processing technologies used;and on the duration of the operations. Asstated previously, the permits range fromthose required for a temporary trailer to themajor environmental permits required underFederal and State regulations and standards.Table 70 shows the status of the major per-

Table 70.–Status of the Environmental Permits for Five Oil Shale Projects

Regular openProject Type of tract EIS DDP approval PSD permit mining permit NPDES permit

R I O B l a n c o Federal lease tract Final programmatic Yesa For 1,000 bbl/d Yes 1st phaseC-a Issued a

Cathedral Bluffs Federal lease tract Final programmatic Yesa For 5,000 bbl/d Yes 1st phaseC-b Issued a

Long Ridge (Union) Private Not applicable Not applicable For 9,000 bbl/d Yes Not requiredb

Colony PrivateC Not applicable Not applicable For 46,000 bbl/d Not yet applied Not requlredb

S u p e r i o r Private/Federal d Not applicable Not applicable Not yet applied Not yet applied Not yet applied

aLlllgallon proceeding over aopro JaI of the momhed DDPbThese operallofls do not plan 10 discharge 10 Surf aCe StreaMScExchange of Federal land and plpellne rlgh[ of way otier BLM and ‘equesled‘Land exchange requested

SOURCE Office of Technology Assessment


mits obtained by five oil shale developers.These facilities are presently in differentstages of commercial development. The RioBlanco, Cathedral Bluffs, Colony, and Superi-or projects involve Federal land, while theUnion project is located on private holdings.DDPs for tracts C-a and C-b had to be ap-proved by USGS because they are part of theFederal Prototype Oil Shale Leasing Program.Four of the projects have already beengranted PSD permits for their facilities. Note,however, that with the exception of the Col-ony project, only small-scale, first-phase con-struction air emissions have been approved.

All of the facilities have to obtain MinedLand Reclamation permits. Rio Blanco, Cathe-dral Bluffs, and Union have all been approvedfor commercial-scale modular operations.Colony and Superior have not yet applied.NPDES permits are required under the CleanWater Act if a plant discharges to a surfacestream. So far Rio Blanco and CathedralBluffs have received such permits for thefirst phase of their commercial development.

The Length of the Permitting Procedure

The time required for preparing and proc-essing a permit application depends on thetype of action being reviewed, the review pro-cedures stipulated under the law, the criteriaused by agencies to judge the application, andthe amount of public participation and con-troversy. If Federal land is involved, then anEIS will most likely be required. This processmay take at least 9 months after the devel-oper applies for permission to proceed withthe project. * Then the applications for thenecessary construction and operation per-mits can be prepared and filed. In the case ofthe current Federal lease tracts, additionaltime was needed to prepare the DDPs for ap-proval by the Area Oil Shale Supervisor ofUSGS.

Once the requirements for an EIS and DDPare satisfied, obtaining all of the needed per-

*The programmatic EIS for the Prototype Leasing Programtook 4 years. Preparation of the draft EIS for the proposed Su-perior land exchange required 2 years.

mits can take more than 2 years. The prep-aration and review of the PSD application isperhaps the most comprehensive and time-consuming step. Baseline air monitoring is re-quired, along with extensive dispersion mod-eling to estimate the effect of the plant’s emis-sions on the region’s air quality. Once thiswork is completed and an application sub-mitted to EPA, the approval process, as stipu-lated under the law, can take as long as 1year. However, EPA tries to rule on the appli-cation within 60 days, and to date an averageof about 90 days has been required. (This in-cludes internal staff review and a period forpublic comment. )

It should be noted that a project would notnecessarily be delayed by the full length ofthe permitting schedule, because other prede-velopment activities such as detailed engi-neering design, contracting, and equipmentprocurement could proceed in parallel, if thedeveloper were willing to accept the risk thatkey permits might eventually proveobtainable.

Disputes Encountered inthe Permitting Procedure

to be un-

The principal problems encountered todate are related to the needs of the regulatoryagencies for technical information, to differ-ing interpretations of environmental law,and, according to developers, to a lack of re-sponsibility for timely action on the part ofthe agencies.

Occidental’s application for a SubsurfaceDisposal permit for its sixth experimentalMIS retort on its property near De Beque,Colo., was delayed for several months by theColorado Water Quality Control Commis-sion’s consideration. (The commission had notrequired permits for the first five retorts. )The commission was concerned about the po-tential for ground water contamination by theabandoned MIS retorts and was not satisfiedwith the evidence presented by Occidentalthat pollution would not occur. Additionaltechnical information was requested, and thecommission insisted on a cooperative environ-


mental monitoring and research program in-volving DOE, the State of Colorado, and sever-al universities. The dispute was resolvedwhen Occidental agreed to the program andthe investigators were given access to Oxy’ssite for sampling and experiments.

As work began on tracts C-a and C-bin late1977, soon after DOI approved the modifiedDDPs, a dispute arose among several environ-mental groups, permitting agencies, and thelessees over the timing of required permits.EPA initially informed the lessees that airquality and State mining and reclamationpermits would not be required until the min-ing of actual in situ retorts began, The envi-ronmental groups maintained that construc-tion commenced with shaft-sinking and con-struction of the surface facilities needed forthe MIS retorts. This work had already begunand, according to the environmental groups,permits should have been in hand, They fur-ther contended that the interpretation of“commencement of construction” used by theagencies evolved during meetings that werenot open to public participation,

EPA’s recently appointed Regional Admin-istrator subsequently redefined “commence-ment of construction” to mean collaring ofthe shaft, an early activity in shaft-sinkingoperations, However, the State reclamationagency maintained that the developers werenot responsible for the previous interpreta-tion of the law, Therefore, operations couldproceed, The State air pollution division post-poned the deadline for application submis-sion until the developers could submit the de-tailed engineering plans required for an emis-sions permit, but did not delay the construc-tion. EPA issued the permit in an expeditiousmanner and work was not significantly de-layed. Because a clear precedent was estab-lished, it is unlikely that this dispute will ariseagain. It took several months to resolve, butactivities on the tracts continued during thisperiod.

Finally, there has been protracted legal ac-tion between three environmental plaintiffsand DOI and the lessees of tracts C-a and C-bover the need for an EIS prior to DOI’s ap-

proval of DDPs that were submitted by thelessees in 1976. This dispute has thus far notdelayed construction on the tracts, It does,however, exemplify the type of uncertaintythat, the developers maintain, discouragesthem from initiating oil shale projects. Theplaintiffs claim that no statement to date hasadequately analyzed the effects of theseplans. Defendants believe that the 1973 pro-grammatic EIS appropriately evaluated the1976 plans and the alternatives to their ap-proval. The Federal district court agreedwith the defendants. The case was heard bythe 10th Circuit Court of Appeals which alsoruled in favor of the defendants.

Other than these disputes, there have beenno substantial interruptions that could bedirectly related to permitting. The onlylengthy application review period involvedColony Development Operation’s PSD airquality permit. EPA did not expedite its re-view of this permit because the applicant in-dicated it was still inactive, awaiting morefavorable project economics. In addition, 1-year suspensions were requested in 1976 bythe lessees of the Federal tracts partiallybecause the baseline air quality conditions onthe tracts exceeded the primary NAAQS forparticulate and the guideline for HC. How-ever, the suspensions were granted for rea-sons not related to the permitting process.

Unresolved Issues

Although many precedents have been es-tablished, there remain unresolved issuesthat sustain a level of uncertainty that maydiscourage some developers from proceeding,whether on private or Federal land. These un-certainties may be more critical than thoseencountered thus far. Several regulations arestill pending that may increase costs or forcechanges in the design of process facilities orcontrol technologies. They may also add tothe control requirements. The pending regu-lations include:

● recordkeeping, reporting, and stipula-tions governing the manufacture and

348 ● An Assessment of 01/ Shale Technologies

handling of toxic substances as requiredunder TSCA;disposal practices and standards for sol-id waste under RCRA;emission and ambient air standards forhazardous air pollutants under theClean Air Act as amended;visibility protection requirements formandatory Class I areas under the CleanAir Act as amended;possible application of the Safe DrinkingWater Act to the brackish ground wa-ters of the Piceance Basin; andpossible application of SMCRA, or simi-lar Federal-reclamation laws, to noncoalminerals.

Some environmental groups maintain thatthe effects of development are so poorly un-derstood that development will entail signifi-cant risks. They believe that adequate regula-tions cannot be promulgated because knowl-edge is lacking about the severity of the risksand about the methods for their control. R&Dand further experience with the industry’soperations may result in the implementationof new regulations that will further reducethe economic attractiveness of oil shale proj-ects. This, however, is an uncertainty whichis inherent in any new industry.

Another problem that may emerge iswhether regulatory agencies will be able tohandle the increasing load of permit applica-tions and enforcement duties. Budgets andpersonnel are limited, and the States in par-ticular have experienced difficulty findingand keeping competent technicians and pro-fessionals. Increased oil shale operations,coal mining, oil and gas development, coal-fired powerplants and synthetic fuel facil-ities, uranium mines and mills, and other min-eral development in the region will furthertax their resources. The dissatisfaction ex-pressed to date may be insignificant com-pared to that which is likely as agencies be-come more overloaded.

Attempts at Regulatory Simplification

Several attempts are being made to simpli-fy regulatory procedures. A case in point isthe action of EPA’s Region VIII office tostreamline the PSD permit application pro-cess. The office evaluated its experience withprocessing such permits and found that in afew cases, there are long review times whenthe applicant was not in a hurry to obtain apermit because the future of the project wasuncertain. An example is the application forthe Colony project, which has been sus-pended for several years. In other instances,delays resulted when the agency was delugedby permit applications prior to the enactmentof new, stricter regulations. An example isthe situation that arose in 1978 when theolder PSD regulations, which did not requireextensive baseline air quality monitoring,were replaced by new regulations that re-quired monitoring for a l-year period. Whenthis happens, the agency’s resources areoverwhelmed and applications are delayed.

Other delays resulted when applicationswere incomplete (information was lacking) orwhen the information that was provided wasdeemed inadequate by the agency. The firstinformational problem could be easily re-duced by a quick review of the application forcompleteness. The second is more difficult,because it involves scientific and technicaljudgment. It reflects, to an extent, the factthat the oil shale processes are new technolo-gies and their effects are not totally under-stood. Standardized procedures are not al-ways available for determining compliancewith the law. This difficulty could be reducedby developing standard procedures whereverpossible. This has been done already in someareas of the PSD process where, for example,the developers are required to use standarddispersion models authorized by EPA.

The Region VIII office recently issued a pol-icy statement that addresses its efforts to im-


prove the permitting procedures. A key ele-ment is designing a standard application thatdefines the specific data needs and recom-mends procedures for obtaining the data.There is also an effort to educate developersin using the application by holding publicworkshops on the permitting procedure. Also,at the Federal level, one focus of the proposedEnergy Mobilization Board is to expediteagency decisionmaking and reduce the im-pacts of new regulatory requirements thatmay emerge after construction or operationsbegin.

The State of Colorado, with funding fromDOE, is designing and testing a permit reviewprocedure for major industrial facilities thatwill coordinate the reviews by Federal, State,and local regulatory agencies. The procedureis also planned to expand the public’s oppor-tunities to become involved in all phases ofproject planning and review. It is being testedwith a controversial molybdenum projectnear Crested Butte, Colo. A handbook will bedeveloped on completion of the test. This mayaid in applying similar methods to the permit-ting process for oil shale plants. *

Policy Options

The policy options presented here rangefrom working to better understand complexregulatory processes, through using the re-sults of such work to reduce the complexities,to waiving the laws or regulations. This rangeencompasses actions over which there is littledisagreement through those which involve ex-treme controversy. Few would argue that reg-ulatory procedures could be improved, whilemany would resist changes that could resultin weakening environmental protections.

Study the Causes of Permitting Delays

Further study of the permitting procedurecould help to identify and eliminate some ofthe causes of regulatory inefficiency. Such

“Colorado hopes this joint review process, which providesfor concurrent rather serial review of applications, will alsoreduce the time needed for review.

studies have been conducted by EPA’s RegionVIII office for the PSD process. The NationalCommission on Air Quality is conducting amore comprehensive evaluation of alterna-tive means for achieving the goals of theClean Air Act with more manageable regula-tory procedures. Similar studies could bemade of other laws and regulations.

Increase the Resources of theRegulatory Agencies

Increasing the personnel and financial re-sources of the Federal regulatory agencieswould allow them to improve their responsecapabilities. The agencies could also providetechnical assistance to the State and localregulators to aid in their decisionmakingprocesses, However, a simple increase inagency funding, without a methodology forcoordinating the expanded resources, wouldnot guarantee that procedures would im-prove.

Improve Coordination Among Agencies andBetween Agencies and the Public

The permitting process might be improvedif coordinated reviews were conducted by thevarious agencies. This strategy would help toidentify and reduce jurisdictional overlapsand to reduce personnel needs and paper-work loads, A major advantage would be theopportunity for sharing analytical responsi-bilities and results. The public hearings thatare required for many separate permits couldalso be consolidated. The strategy could bepatterned after the voluntary joint reviewprocesses that are being developed in Col-orado and other States. However, unless theapproach were mandated, it is questionablethat interagency cooperation would be sig-nificantly improved.

Another approach would involve the estab-lishment of a regional environmental monitor-ing system to determine baseline conditionswithin all areas to be affected by oil shaleprojects. The system could better character-ize baseline conditions than could individual,uncoordinated monitoring programs. It might

350 ● An Assessment of O// Shale Technologies

reduce the duration and the cost of the ad-vance monitoring programs that are requiredof permit applicants. Site-specific measure-ments would still be required to characterizebiological communities, soils, hydrology, andgeology for projects involving Federal land.Baseline surveys could be conducted by Fed-eral agencies on potential lease tracts toshorten the time between a leasing decisionand commercialization. The cost of the pro-gram could be included in the cost of thelease. Individual monitoring of stack emis-sions, water discharges, and reclamation ef-forts would also still be needed as the proj-ects proceeded.

Improved coordination of public participa-tion might also shorten review time by reduc-ing controversy, political confrontation, andlitigation. Procedures might include advancepublic notification of the status of permit ap-plications, the dissemination of technical in-formation and R&D results, and the more di-rect involvement of the public in an agency’sdecisionmaking process through, for exam-ple, workshops and public meetings. It is pos-sible that increasing the public’s awarenessof the characteristics of a project might leadto perceptions of greater risk. On the otherhand, education could lessen nonproductivediscussions and confrontations. In any case,it may be difficult to educate the public in thetechnical aspects that determine whether anapplication satisfies the standards. To main-tain a high level of participation, some inter-vener groups may seek financial and techni-cal assistance. This would be controversial,especially from the point of view of the devel-opers.

Clarify the Regulations andthe Permitting Procedure

One option would be to expedite promulga-tion of standards for visibility and hazardousemissions under the Clean Air Act, and to setthe as yet undefined NSPS for oil shaleplants. Additional regulations could also bedefined under RCRA, TSCA, and other laws.These actions would eliminate many of theregulatory uncertainties and would allow the

developers to integrate controls for the newstandards into their plant designs. If it is de-sired to reduce developer risks, new stand-ards should be firmly established and notsubject to change for an extended period.This may not be appropriate, since early ex-perience with the industry may indicate aneed to modify the standards to achieve thedesired level of protection. In addition, theymay be difficult to establish. Excessively laxstandards would not adequately protect theenvironment; excessively strict ones mightunnecessarily preclude development. Thesehazards are particularly applicable to settingNSPS.

Another approach would be to simplify thepermitting procedures themselves, based oninformation from the investigations suggestedunder the first option. This would have theadvantage of retaining the protection of theexisting laws while making it easier to complywith them. However, problems (such as theuncertain status of applications in progress)might arise during the transition from the oldregulatory system to the new. It is also oftendifficult to isolate the substance of environ-mental protection laws from the implementa-tion procedures. Any proposed changes in theprocedures would need careful examinationby the agencies, the developers, and the pub-lic.

A third approach would be to establish de-tailed, standardized specifications for permitapplications. This would reduce the problemof insufficient data being provided with theapplications and the delays that would becaused when agencies request the additionalinformation they feel is necessary for a thor-ough review. Fully comprehensive standard-ized forms are probably not possible, andsome interactions after an application is sub-mitted will still be needed.

A fourth option would be to have a mora-torium on new regulations until some of theactual effects of development are determinedon the Prototype Program lease tracts. (Moni-toring of environmental effects and develop-ment of control techniques is one of the major


objectives of the Program. ) A disadvantage isthat the regulatory uncertainties would re-main. An advantage is that the regulationscould be promulgated from a better knowl-edge base,

Expedite the Permitting Procedure

The proposed Energy Mobilization Boardwould expedite permitting by negotiating aproject schedule with a developer and thenenforcing the schedule by making regulatorydecisions if the responsible agency does notdo so within a specified period. Proponents ofthis strategy point out the advantages of acentral authority that could provide a singlepoint of contact between the developer andthe regulatory system. Opponents feel thatsuch an authority would add another layer ofbureaucracy, would increase controversyover the projects that are expedited, andwould ultimately not have substantial effectson permitting delays.

Another method would be to limit the peri-od during which litigation can be initiatedagainst a particular permitting action, Thismechanism could be similar to that employedin the case of the Trans-Alaska oil pipeline. Itwould reduce the risk of agency actions beingsubjected to legal challenges that could jeop-ardize a project’s completion schedule. Itshould be noted, however, that legal mecha-nisms already exist in some specific laws tolimit the period of litigation, The expeditingstrategy could extend this protection to most,if not all, of the relevant statutes,

Limit the Application of New Environmental Lawsand Regulations

Plants already under construction, or thatare operating, could be exempted from theprovisions of new environmental laws andregulations. This approach—’’grandfather-ing ” —is embodied in the legislation for theEnergy Mobilization Board. It would removemany of the regulatory uncertainties. How-ever, it is surrounded with controversy be-cause new regulations might be needed todeal with problems that could not be discov-ered until after operations begin. Many of thepresent laws contain provisions to exempt ex-isting facilities from new requirements.These include either automatic exemptionclauses or economic criteria against whichthe new regulatory requirements must betested.

Waiving Existing Environmental Laws

This strategy would exempt a project fromthe provisions of some or all existing environ-mental laws and regulations that might delayor prevent its construction and operation.This measure would remove virtually all ofthe problems and delays associated with thepermitting. However, it would have seriouspolitical, environmental, and social ramifica-tions since it could arbitrarily preempt envi-ronmental protection under the law. Further-more, the waivers might give an undeservedcompetitive advantage to the developers whoreceived them. The allocation of the waiverswould be highly controversial, The extent towhich this action would speed the deploy-ment of the industry is unclear.

— . - .


Chapter 8 References

‘Environmental Protection Agency, Trace E]e-ments Associated With Oil S~ale and Its Process-ing, EPA-908/4-78-003, prepared by TRW and DRIunder contract No. 68-02-1881, May 1977, p. 2.

2T. C. Borer and J. W. Hand, Identification andProposed Control o~ Air Pollutants From Oil ShaleOperations, prepared by the Rocky Mountain Divi-sion, The Pace Co. Consultants and Engineers,Inc., for OTA, October 1979, p. 38.

‘Environmental Protection Agency, MonitoringEnvironmental Impacts of the Coal and Oil ShaleIndustries: Research and Development Needs,EPA-600/7-77-015, February 1977, p. 138.

%upra No. 2, at p. 20.‘Denver Research Institute, Predicted Costs of

Environmental Controls for a Commercia l OilShale Industry: Volume I—An Engineering Ana]y-sis, prepared for the Department of Energy undercontract No. EP-78-S-O2-51O7, July 1979.

‘Environmental Protection Agency, A Prelimi-nary Assessment of the Environmental ImpactsFrom Oil Shale Development, prepared by TRWand DRI under contract No, 68-02-1881 (EPA-600/7-77-069), July 1977, P. 104.

7Battelle Northwest Laboratories and Damesand Moore, Environmental Impact Analysis: Ap-pendix 13—Air Studies, prepared for Colony De-velopment Operation, October 1973.

‘Rio Blanco Oil Shale Project, Detailed Develop-ment Plan Tract C-a: Environmental Protectionand Monitoring, vol. 4, March 1976.

‘Rio Blanco Oil Shale Project, Detailed Develop-ment Plan Tract C-a: Environmental Protectionand Monitoring, vol. 3, May 1977.

‘[statement by Terry Thoem, EnvironmentalProtection Agency, Region VIII, as reported in theminutes of the 25th meeting of the Oil Shale Envi-ronmental Advisory Panel, Grand Junction, Colo.,May 2 and 3, 1979, pp. 130-131,

I INational Commission on Air Quality, Report ofthe Atmospheric Modeling Review Panel of theNational Commission on Air Quality, (preliminarydraft), to be published in February 1980.

121bid.1‘Ibid,“E, F, Bates and T. L. Thoem (eds, ), Pollution

Control Guidance for Oil Shale Development, re-vised draft report, Environmental ProtectionAgency, Cincinnati, Ohio, July 1979, p, 4-46.

15 Colony Development Operation, An Environ-mental Impact Analysis for a Shale Oil Complex atParachute Creek, Colorado, vol. I, 1974.

1hJ. C. Ward, G. A. Margheim, and G, O. Lof,Water Pollution Potential of Spent Oil ShaleResidues, report for the Water Quality Office, En-vironmental Protection Agency, Colorado StateUniversity, Fort Collins, Colo., 1971.

17National Academy of Sciences, Mining andProcessing of Oil Shale and Tar Sands—A Work-ing Paper Prepared for the Committee on SurfaceMining and Reclamation, Washington, D. C., 1979,p. 89.

1%upra No. 5,‘gIbid.2(}Supra No. 17, at p, 91.21J. P. Fox, K. K, Mason, and J. J. Duvall, “Parti-

tioning of Major, Minor, and Trace Elements Dur-ing Simulated In Situ Oil Shale Retorting in a Con-trolled-State Retort, ” Proceedings of the TwelfthOil Shale Symposium (J. H, Gary, cd.), ColoradoSchool of Mines Press, Golden, Colo., 1979, pp.58 -71 ,

22F. C, Hass, “Analysis of TOSCO II Oil ShaleRetort Water, ” paper presented at ASTM Sym-posium D-199.33 on Analysis of Wastes Associ-ated With Alternative Fuel Production, Pitts-burgh, Pa., June 4-5, 1979,

21E. W. Cook, “Organic Acids in Process WaterFrom Green River Oil Shale, ” Chemistry & Indus-try, May 1, 1971, p, 485.

“G. W. Dawson and B, W. Mercer, “Analysis,Screening and Evaluation of Control Technologyfor Wastewater Generated in Shale Oil Develop-ment,” Quarterly Reports, Batelle Pacific North-west Laboratory, Richmond, Wash., January1977-March 1979.

25Water Purification Associates, A Study ofAerobic Oxidation and Allied Treatments for Up-grading In Situ Retort Waters, contract No, EW-78-C-20-0018 with Laramie Energy TechnologyCenter, Department of Energy, Quarterly StatusReport, August 1979.

2%upra No. 14.27Supra No. 21,%upra No. 22.“National Academy of Sciences, Water Quality

criteria, 1972, Environmental Protection Agencypublication (EPA-R-3-73-033), Washington, D, C.,March 1973.

1{]Ibid,‘lSupra No. 14, at p. 3-64.‘21bid.“J. B, Weeks, et al., Simulated E~~ects of Oil-

Shale Development on the Hydrology of Piceance


Basin, Ccdoraclo, Professional Paper 908, U.S. Geo-logical Survey, Washington, D, C., 1974, p. 34.

“Ibid., p. 44.“)Ibid,, p. 39.“]Ibid., p. 40.Wupra No. 14.%upra No. 6.“A. L. Hines, The Role of Spent Shale in Oil

Shale P r o c e s s i n g and tbe M a n a g e m e n t o-f E n v i r o n -mental Residues, Department of Energy, reportTID-28586, ERDA-Laramie Energy ResearchCenter, Laramie, Wyo., April 1, 1978.

‘“B. W. Mercer, et al., “Assessment of ControlTechnology for Shale Oil Wastewaters, ’” paperpresented at Environmental Control TechnologySymposium, Department of Energy, November1978.

“lB. L, Harding and K. D. Lindstedt, et al., Re-moval of Ammonia and Alkalinity From Oil ShaleRetort Waters, prepared for Laramie EnergyTechnology Center, Department of Energy, con-tract No. DE-AS20-78-ET-13096, April 1979.

“K. D. Lindstedt and E. R. Bennett, Report onCharacterization and Treatment of Retort WatersFrom In Situ Oil Shale Retorting, Civil, Environ-mental, and Architectural Engineering Dept., Uni-versity of Colorado, August 1977.

“Osmonics, Inc., “Application Test Report”(Study of the Application of Reverse Osmosis toTreatment of Oil Shale Wastewaters), report inpreparation for Laramie Energy Technology Cen-ter, Department of Energy, 1979.

‘“Water Purification Associates, A Study of Re-verse Osmosis for Treating Oil Shaie Process Con-densates and Excess Mine Drainage Water, quar-terly progress report, prepared for Laramie Ener-gy Technology Center, Department of Energy, con-tract No. DE-AC2O-79LC1OO89, September 1979.

“E. A. Ossio, et al,, “Anaerobic Fermentation ofSimulated In Situ Oil Shale Retort Water, ” Amer-ican Chemical Society Division of Fuel ChemistryReprints, vol. 23, No. 2, 1978, pp. 202-213.

“R. R. Spencer, Anuero&c Treatment o-f Waste-water Generated During Shale Oil Production(draft report), BattelIe Pacific Northwest Labora-tory, 1979.

%upra No. 24.%upra No. 25.‘“B. Harding, et al., “Study Evaluates Treat-

ments for Oil-Shale Retort Water, ” IndustrialWastes, September/October 1978, pp. 28-33.

“lA. B. Hubbard, “Method for ReclaimingWastewater From Oil Shale Processing, ” Ameri-can Chemical Society Division of Fuel Chemistry

Reprints, vol. 15, No. 1, March-April, 1971, pp.21-25.

“Supra No. 14, at p. 3-44,‘)’ Ibid., p. 5-5o.‘] National Safety Council, Accident Facts, stock

No. 021.57, Chicago, 1977.“R. H. Flinn, et al., Silicosis in the Metal Mining

Industry: A Reevaluation, 1958-1961, PublicHealth Service, Pub. No, 1076, 1963.

“Ibid.“)Personal communication with George Weems,

Supervisory Physical Scientist, Industrial HealthBranch, Denver Technical Support Center, Min-ing Safety and Health Administration, Depart-ment of Labor, Jan. 22, 1980.

“1. P. Maripuu, Puusaar, “Spirographic a n dRoentgenofunctional Characterization of Pulmo-nary Emphysema in Bituminous Shale Miners, ”Gyg. Tr. Prof. Zabol., vol. 15, No. 12, 1971, pp.51-53.

‘{{W. K. C. Morgan and N. Zapp, “RespiratoryDisease in Coal Miners, ” American Review o.f I?es -piratory Diseases, vol. 113, 1976, pp. 531-559.

‘)OL. M. Irwig and P. Rochs, “Lung Function andRespiratory Symptoms in Silicotic and Nonsilicot-ic Gold Miners, ” A m e r i c a n R e v i e w of R e s p i r a t o r yDiseases, vol. 117, 1978, pp. 429-435.

‘I(’V. A. Kung, “Morphological Investigations ofFibrogenic Action of Estonian Oil Shale Dust, ” En-vironment tal Health Perspectives, vol. 30, 1 9 7 9 ,PP. 1 5 3 - 1 5 6 .

“W. E. Wright and W. N, Rem, “A PreliminaryReport: Investigation for Shalosis Among OilShale Workers, ” presented at Park City Environ-mental Health Conference, Park City, Utah, Apr.4-7, 1979.

‘)’J. Rudnick and G. L. Voelz, “An OccupationalHealth Study of Paraho Oil Shale Workers,”’ pre-sented at Park City Environmental Health Con-ference, Park City, Utah, Apr. 4-7, 1979.

“J. Costello, “Morbidity and Mortality Study ofOil Workers in the United States, ” EnvironmentalHealth Perspectives, vol. 30, 1979, pp. 205-208,

%upra No. 107.‘)7L. M, Holland, D. M. Smith, and R, G. Thomas,

“Biological Effects of Raw and Processed OilShale Particles in the Lungs of Laboratory Ani-reals, ” Environmental Health Perspectives, vol.30, 1979, pp. 147-152.

‘)’)L. M. Holland, W, D. Span, and L. L. Garcia,“Inhalation Toxicology of Oil Shale-Related Mate-r i a l s , presented at Park City EnvironmentalHealth Conference, Park City Utah, Apr. 4-7,1979.

— —


b7R, A. Renne, J. E. Lund, K, E. McDonald, et al,,“Morphologic Effects of Intratrachially Admin-istered Oil Shale in Rats, ” presented at Park CityEnvironmental Health Conference, Park City,Utah, Apr. 4-7, 1979.

‘8Supra No. 63.b9B. T. Scheb, “Noise in the Mining Industry: Its

Effects, Measurement, and Control, ” Proceedingsof the Symposium on Industrial Hygiene for A4in-ing and Tunneling, American Conference of Gov-ernmental Industrial Hygieniests, Cincinnati,Ohio, 1978.

‘[’M. Blick, et al., “Noise,” Medicine in the A4in-ing Industries (J. M. Rogan, cd.), published by F. A.Davis, Philadelphia, Pa,, 1974, p. 244.

711. Berenblum and R. Schoental, “CarcinogenicConstituents of Shale Oil, ” British Journal of Ex-perimental Pathology, vol. 24, 1943, pp. 232-239.

72A. Scott, “The Occupation Dermatoses of theParaffin Workers of the Scottish Shale Oil Indus-try, ” British Medical Journal, vol. 1, 1922, pp.381-385.

7JM. Purde and S, Etlin, “Cancer Cases AmongWorkers in the Oil-Shale Processing Industry, ”presented at Park City Environmental Health Con-ference, Park City, Utah, Apr. 4-7, 1979.

“M. Purde and M. Rahn, “Cancer Patterns inthe Oil Shale Area of the Estonian Soviet SocialistRepublic, ” Environmental i+ea)t~ Perspectives,vol. 30, 1979, pp. 209-210.

75A, Leitch, “Paraffin Cancer and Its Experi-mental Production, ” British Medical Journal, vol.2, 1922, pp. 1104-1106.

7bI. Berenblum and R. Schoental, “The Differ-ence in Carcinogenicity Between Shale Oil andShale, ’’British Journal of Experimental Pat~ology,vol. 25, 1944, Pp. 9 5 - 9 6 .

“C. C. Twort and J. M. Twort, “Classification ofFour Thousand Experimental Oil and Tar Skin Tu-mors of Mice, ” Lancet, vol. 1, 1930, pp.1331-1335.

“J, M. Holland, et al., “Skin Carcinogenicity ofSynthetic and Natural Petroleums, ” Journal of Oc-cupational Medicine, vol. 21, 1979, pp. 614-618.

7YR. M. Coomes, “Carcinogenic Testing of OilShale Materials, ” Twelfth Oil Shale SymposiumProceedings, Golden, Colo., The Colorado Schoolof Mines Press, November 1979.

“)Ibid.“Ibid.821bid.‘]Ibid.‘“J. J, Zone, “Cutaneous Effects of Shale Oil,”

presented at Park City Environmental Health Con-ference, Park City, Utah, Apr. 4-7, 1979.

85D. J. Birmingham, Interim Report on the ShaleOil Study, Public Health Service, Cincinnati, Ohio,1955 .

8bTabershaw-Cooper Associates, Inc., A Mortal-ity Study of Petroleum Refinery Workers, projectOH-1, Medical Research Report No. EA-7402,American Petroleum Institute, September, 1974.

87N, M. Hanis, K. M. Stavraky, and J. L. Flowler,“Cancer Mortality in Oil Refinery Workers, ”Journal of Occupational Medicine, vol. 21, No. 3,1979, Pp. 167-174,

88G. Theriault and L. Goulet, “A Mortality Studyof Oil Refinery Workers, ’’Journal of OccupationalMedicine, vol. 21, No. 5, 1979, pp. 367-370.

89M+ B. BIOCh and D. Kilburn (editors), proc-essed Shale Revegetation Studies, 1965-1973, Col-ony Development Operation, Atlantic Richfieldco., 1973.

‘(’W. R, Schmehl and B, D. McCaslin, “SomeProperties of Spent Oil Shale Significant to PlantGrowth,” Ecology and Reclamation of DevastatedLand, vol. I (R. J, Hutnik and G, Davis, eds.), pub-lished by Gordon and Breach, New York, 1973,PP. 27-43.

“’J. C. Ward and S. E. Reinecke, Water PollutionPotential of Snow~all on Spent Oil Shale Residues,prepared by the Environmental Engineering Pro-gram, Department of Civil Engineering, ColoradoState University for the Bureau of Mines, LaramieEnergy Research Center, under grant No.0111280, 1972,

‘zIbid.“James R. Meiman, Infiltration Studies in the Pi-

ceance Basin, Colorado, Thorne Ecological Insti-tute, technical publication No. 12, 1975.

‘AIbid,‘5 Forest Service, Users Guide to Soils, Mining

and Reclamation in the West, general technicalreport INT-68, Intermountain Forest and RangeExperiment Station, U.S. Department of Agricul-ture, 1979.

“W. J. Culbertson, et al . , P r o c e s s e d ShaleStudies: Environmental Impact Analysis, Appen-dix 5, Colony Development Operation, AtlanticRichfield Co., 1974.

‘7 Supra No, 95,“R. M. Dixon, “Soil Imprinting for Increasing

Land Productivity, ” presented at the 33rd AnnualMeeting of Soil Conservation Society of America,July 30-Aug. 2, 1978, Denver, Colo, Also printed inthe Journal of Soil and Water Conservation, 1978.

‘gSupra no. 89.‘(WRio Blanco Oil Shale Co., Revegetation Pro-

gram 1978 Annual Report, submitted to Rio BlancoOil Shale Co., Denver, Colo,, by NUS Corp., Den-


ver, Colo., March 1979.II)]C. Wayne Cook, Rehabilitation Potential and

Practices of Colorado Oil Shale Lands, progressreport for period June 1978- May 31, 1979, pre-pared for the Department of Energy by ColoradoState University under contract No. EY-76-S-02-4018, 1979.

I“zC. Wayne Cook, et al., Revegetation Guide-lines for Surface Mined Areas, Colorado StateUniversity, Range Science Department ScienceSeries No. 16, 1974.

‘()] Ibid.‘(”R. R. Ericsson and P. Morgan, “The Economic

Feasibility of Shale Oil: An Activity Analysis, ”Bell Journal of Economics, vol. 9, 1978, pp.457-487.

“]5Supra No. 1.‘(’t) Supra No. 96.11]71bid,W5upra No. 90.%upra No. 100.‘loR. C. Woodmansee, et al, “Nitrogen in Dras-

tically Disturbed Lands, ” Forest Soils and LandUse (C. T. Youngberg, cd.), Department of Forestand Wood Sciences, Colorado State University,Fort Collins, 1979, pp. 376-392,

‘]] Supra No. 101.“zIbid.11 ‘F. B. Reeves, et al,, “The Role of Endomycor-

rhizae in Revegetation Practices in the Semi-AridWest: A Comparison of Incidence of Mycorrhizaein Severely Disturbed vs. Natural Environments,American Journal of Botany, vol. 66, No, 1, 1979,pp. 6-13.

“’Supra No. 101.‘}%upra No. 16.“’Supra No. 90.1l’H. P. Harbert III, et al., Vegetative Stabiliza-

tion of Spent Oil Shales: Vegetation, Moisture,Salinity and Runoff 1973-1976, 1978,

I l~H. p. Harbert 111, et al., ~YSimeter study onthe Disposal of Paraho Retorted Oil Shale, Indus-trial Environmental Research Laboratory, Officeof R&D, Environmental Protection Agency, Cincin-nati, Ohio (EPA-600/7-79-188), 1979.

IIqW. A. Berg, et al,, Vegetative Stabilization ofUnion Oil Company Process B Retorted Oil Shale2975-1978, Colorado State University ExperimentStation, technical bulletin No. 135, 1979,

121)J. T, Herron, et al., Vegetation and LysimeterStudies on Decarbonized Oil Shale, Colorado StateUniversity Experiment Station, technical bulletinNo, 136, 1980.

12]L. A. Richards (cd.), Diagnosis and Improve-ment of Saline and Alkali Soils, U.S. Department ofAgriculture Handbook No. 60, 1954.

‘221. F. Wymore, Water Requirement for Stabili-zation of Spent Shale, doctoral dissertation, Colo-rado State University, Fort Collins, Colo., 1974,

‘z’D. D. Runnells, et al., “Release, Transport,and Fate of Some Potential Pollutants, ” in TraceElements in Oil Shale, report No. COO-4Ol 7-2, Envi-ronmental Trace Substances Research Program,University of Colorado, Denver, Colo., 1978, pp.49-97.

‘“M. K. Kilkelly, et al., “Trace Elements inPlants Growing on Processed Oil Shales, ” inT r a c e E l e m e n t s i n Oil Shale, r epor t No ,COO-4017-2, University of Colorado, Denver, Colo.,1978, pp. 98-134.

‘25 Supra No. 16.‘2hSupra No. 117.‘271bid,‘28Supra No, 100.‘2%upra No. 96.‘30Fish and Wildlife Service, The Plant Informa-

tion Network: Volumes I-W, U.S. Department ofthe Interior FWS/OBS-77/38-41. Supporting com-puter data base located at the Department of Bot-any and Plant Pathology, Colorado State Univer-sity, Fort Collins, Colo.

1“C. M. McKell, et al., Selection, Propagation,and Field Establishment of Native Plant Species onDisturbed Arid Lands, Institute for Land Reha-bilitation, Utah Agricultural Experiment Station,Utah State University, 1979.

1‘zSoil Conservation Service, Plant Materials forUse on Surface Mined Lands in Arid and Semi-Arid Regions, U.S. Department of Agriculturehandbook SCS-TP 157, Lincoln, Nebr. (in press).

‘]’ Forest Service, User Guide to Vegetation,Mining and Reclamation in the West, general tech-nical report INT-64, Intermountain Forest andRange Experiment Station, U.S. Department of Ag-riculture, 1979.

‘ “A. Plummer, et al., Restoring Big-Game Rangein Utah, Utah Division of Fish and Game publica-tion No. 68-3, 1968.

l’5Supra No. 130.‘%upra No. 133.‘%upra No. 101.“nIbid,‘Y5upra No. 133.1’OK. A. Crofts and C. M. McKell, Sources of

Seeds and Planting Materials in the WesternStates for Land Rehabilitation Projects, Utah Agri-

356 ● An Assessment 01011 Shale Technologies

culture Experiment Station Land RehabilitationSeries No. 4, Logan, Utah, 1977.

‘“’ Supra No. 133.‘“2 Supra No. 101.1“Supra No. 100,‘“’N. C. Frischknecht and R. B. Ferguson, Reveg-

etating Processed Oil Shale and Coal Spoils onSemi-Arid Lands, interim report, EPA-600/7-79-068, Environmental Protection Agency, Cin-cinnati, Ohio, 1979.

‘“R. W. Tinus, et al. (eds,), Proceedings of theNorth American Conta iner ized Forest Tree Seed-ling Symposium, Great Plains Agricultural Councilpublication No. 68, 1974,

‘%upra No. 131.‘“71bid.““Supra No. 132.“’Supra No. 117.‘%upra No. 132.“]Bureau of Land Management, Piceance Plan-

ning Unit Resource Analysis, September 1970.“’Bureau of Land Management, White River

Management Framework P~an, January 1972.‘s’K. C. Vories, A Vegetation Inventory and

Analysis of the Piceance Basin and AdjacentDrainages, master’s thesis, Western State Col-lege, Gunnison, Colo., 1974.

‘“J. A. Tiedeman, et al., Phyto-Edaphic C~assifi-cation of the Piceance Basin, Colorado State Uni-versity, Range Science Department Science Se-ries No. 31, 1978.

I“Ibid.“’)Rocky Mountain Oil and Gas Association Oil

Shale Committee, Summary of Industry Oil ShaleEnvironmental Studies and Selected Bibliographyof Oil Shale Environmental References, Denver,Colo., 1975.

15%upra No. 89.“HJ. M. Merino, et al., “Reclamation of Spent Oil

Shale,” Mining Congress ]ournal, vol. 63, No. 10,1977, pp. 31-36.

‘%upra No. 117.‘fWupra No. 118,“)lSupra No. 119.“)2Supra No. 120.‘(]] Supra No. 89.‘[)’ Ibid.““C. M. McKell, Achieving Effective Revegeta-

tion of Disposed Processed Oil Shale: A ProgramEmphasizing Natural Methods in an Arid Environ-ment, Utah State University, Agriculture Experi-ment Station Land Rehabilitation Series No. 1,1976.

‘Wupra No. 16.‘t)7Supra No. 89.‘%upra No. 117.“%upra No. 90.‘%. C. Lipman, “Union Oil Company Revegeta-

tion Studies, ” Environmenta~ Oil Shale S y m -posium, Colorado School of Mines, Oct. 9-10,1975, pp. 165-180.

‘7’ Supra No. 119.“2Supra No. 118.“]Supra No, 101.“’Ibid.

Documents

An Assessment of Oil Shale Technologies (Part 10 of 18)